U.S. patent application number 10/027677 was filed with the patent office on 2002-12-05 for production and use of a premium fuel grade petroleum coke.
This patent application is currently assigned to Environmental & Energy Enterprises, LLC. Invention is credited to Etter, Roger G..
Application Number | 20020179493 10/027677 |
Document ID | / |
Family ID | 27071078 |
Filed Date | 2002-12-05 |
United States Patent
Application |
20020179493 |
Kind Code |
A1 |
Etter, Roger G. |
December 5, 2002 |
Production and use of a premium fuel grade petroleum coke
Abstract
A premium "fuel-grade" petroleum coke is produced by modifying
petroleum coking technology. Coking process parameters are
controlled to consistently produce petroleum coke within a
predetermined range for volatile combustible material (VCM)
content. The invention includes a process of producing a coke fuel,
the method comprising steps: (a) obtaining a coke precursor
material derived from crude oil and having a volatile organic
component; and (b) subjecting the coke precursor material to a
thermal cracking process for sufficient time and at sufficient
temperature and under sufficient pressure so as to produce a coke
product having volatile combustible materials (VCMs) present in an
amount in the range of from about 13% to about 50% by weight. Most
preferably, the volatile combustible materials in the coke product
typically may be in the range of from about 15% to about 30% by
weight. The present invention also provides methods for (1)
altering the coke crystalline structure, (2) improving the quality
of the coke VCM, and (3) reducing the concentration of coke
contaminants. Fuels made from the inventive coke product and
methods of producing energy through the combustion of such fuels
are also included. Finally, novel environmental control techniques
are developed to take optimal advantage of the unique
characteristics of this upgraded petroleum coke.
Inventors: |
Etter, Roger G.;
(Cardington, OH) |
Correspondence
Address: |
STANDLEY & GILCREST LLP
495 METRO PLACE SOUTH
SUITE 210
DUBLIN
OH
43017
US
|
Assignee: |
Environmental & Energy
Enterprises, LLC
|
Family ID: |
27071078 |
Appl. No.: |
10/027677 |
Filed: |
December 20, 2001 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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10027677 |
Dec 20, 2001 |
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09556132 |
Apr 21, 2000 |
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10027677 |
Dec 20, 2001 |
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09763282 |
Feb 20, 2001 |
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Current U.S.
Class: |
208/131 ;
208/108; 208/111.01; 208/142; 208/143; 208/144; 208/145 |
Current CPC
Class: |
C10B 55/00 20130101;
C10L 9/00 20130101; C10L 9/10 20130101; C10L 9/04 20130101; C10B
57/06 20130101; C10B 57/005 20130101; C10L 9/02 20130101; C10G
9/005 20130101; C10L 5/00 20130101 |
Class at
Publication: |
208/131 ;
208/108; 208/111.01; 208/142; 208/143; 208/144; 208/145 |
International
Class: |
C10G 009/00; C10G
047/00; C10G 045/00 |
Foreign Application Data
Date |
Code |
Application Number |
Aug 20, 1999 |
US |
PCT/US99/19091 |
Claims
What is claimed is:
1. A process of producing a coke product, said process comprising:
providing a coke precursor material; subjecting said coke precursor
material to a thermal cracking process; and maintaining the ratio
of asphaltic coke to thermal coke so as to promote the production
of sponge coke; wherein said coke product is comprised of sponge
coke in an amount in the range of about 40% to 100% by weight.
2. The process of claim 1 wherein: said coke precursor material
includes a volatile organic component; and said coke product has
volatile combustible materials (VCMs) present in an amount in the
range of from about 13% to about 50% by weight.
3. The process of claim 1 wherein the ratio of asphaltic coke to
thermal coke is maintained by controlling at least one variable
selected from the group consisting of coke precursor material
characteristics, heater outlet temperature, coke drum temperature,
coke drum pressure, coker recycle rate, coke drum thermal quench,
coke drum chemical reaction quench, and combinations thereof.
4. The process of claim 3 wherein said coke drum thermal quench,
said coke drum chemical reaction quench, or combinations thereof
are added into a coke drum via injection systems selected from the
group consisting of an existing anti-foam injection system modified
drill stem, an injection lance at the top of the coke drum, and
combinations thereof.
5. The process of claim 1 wherein said thermal cracking process is
selected from the group consisting of delayed coking, Flexicoking,
and other thermal cracking processes with by-product coke
production.
6. The process of claim 1 wherein said coke product has porosity
characteristics suitable for adsorption use.
7. The process of claim 6 wherein the adsorption characteristics of
said coke product are improved by performing at least one step
selected from the group consisting of: decreasing the ratio of
asphaltic coke to thermal coke; including feed additives in said
coke precursor material that are adapted to release low molecular
weight gases during said thermal cracking process; injecting low
molecular weight gases into a coke mass in a coke drum at the start
of a decoking cycle of said thermal cracking process;
hydroprocessing said coke product with sufficient hydrogen
addition, temperature, pressure, catalyst activity, and residence
time; treating said coke product via chemical extraction of
asphaltenes and resins with sufficient solvent, temperature,
pressure, and residence time; treating said coke product via
chemical activation with sufficient chemical activator,
temperature, pressure, and residence time; and combinations
thereof.
8. The process of claim 6 further comprising impregnating and/or
adsorbing in said coke product at least one chemical compound
having desired combustion characteristics and/or characteristics
that otherwise enhance the fuel properties of said coke
product.
9. The process of claim 8 wherein at least one volatile combustible
material (VCM) is deposited via evaporation in said coke product
and/or adsorbed in said coke product from a coke quench solution
used in said thermal cracking process.
10. The process of claim 8 wherein at least one ionizing agent is
deposited via evaporation in said coke product and/or adsorbed in
said coke product from a coke quench solution used in said thermal
cracking process.
11. The process of claim 8 wherein at least one oxygen-containing
compound is deposited via evaporation in said coke product and/or
adsorbed in said coke product from a coke quench solution used in
said thermal cracking process.
12. The process of claim 8 wherein catalytic properties of said
coke product are enhanced by the deposition via evaporation in said
coke product and/or adsorption in said coke product of at least one
catalyst or catalyst enhancement chemical from a coke quench
solution used in said thermal cracking process.
13. The process of claim 6 wherein said coke product has sufficient
adsorption character to be used for at least one adsorption
application selected from the group consisting of solvent vapor
recovery, liquid purification, water purification, gas
purification, air purification, and flue gas cleanup.
14. The process of claim 13 wherein said sponge coke has a
honeycomb crystalline structure that is adapted to provide low
pressure drop in said at least one adsorption application.
15. The process of claim 14 wherein said coke product is adapted to
be removed from a coke drum in at least one section substantially
without destroying the integrity of said honeycomb crystalline
structure.
16. The process of claim 6 further comprising adding at least one
chemical compound to said coke product to enhance adsorption
characteristics of said coke product.
17. The process of claim 16 wherein: at least one sulfur compound
is added to said coke product by a process selected from the group
consisting of adsorption and impregnation, wherein said at least
one sulfur compound is adapted to enhance the adsorption of mercury
and/or another toxic chemical from a gas stream.
18. The process of claim 1 further comprising adding to said coke
precursor material at least one component selected from the group
consisting of plastics, rubbers, and similar materials.
19. The process of claim 18 wherein said at least one component is
added to said coke precursor material downstream of a feed heater
via at least one system selected from the group consisting of
grinding systems, pulverizing systems, and extruder injection
systems.
20. The process of claim 6 further comprising adding at least one
chemical compound to said coke product to enhance catalyst activity
and properties of said coke product.
21. A coking process comprising: providing a coke drum containing a
coke mass and a vapor phase above said coke mass; and injecting a
quench medium in said vapor phase during a coking cycle; whereby
thermal cracking in said vapor phase is quenched during said coking
cycle.
22. The coking process of claim 21 wherein said thermal cracking is
inhibited by a quench selected from the group consisting of a
thermal quench, chemical reaction quench, and combinations
thereof.
23. The process of claim 21 wherein: said quench medium is selected
from a group consisting of hydrogen, coker gas oil, and
combinations thereof; and said quench medium is injected via a
modified drill stem positioned in said coke drum during said coking
cycle and maintained at a level about 0.5 to about 10 feet above
said coke mass.
24. A process for removing sulfur from petroleum coke, said process
comprising: adding at least one sulfur reagent to said petroleum
coke; and combusting said petroleum coke such that said at least
one sulfur reagent reacts with sulfur in said petroleum coke to
form solid particles; wherein said solid particles are adapted to
be collected.
25. The process of claim 24 wherein: at least one sulfur reagent is
added to said coke product by a process selected from the group
consisting of adsorption and impregnation
26. The process of claim 24 wherein: said at least one sulfur
reagent includes a compound comprising a component selected from
the group consisting of earth metals and alkaline earth metals.
27. The process of claim 25 wherein said at least one sulfur
reagent is added to said petroleum coke by adsorption from a coke
quench solution during a coking process.
28. The process of claim 26 wherein said at least one sulfur
reagent is selected from the group consisting of calcitic hydrates
and dolomitic hydrates.
29. A delayed coking process for producing a coke product, said
process comprising: adding to a coke precursor material at least
one component selected from the group consisting of plastics,
rubbers, coal, wood, cardboard, paper, cellulosic materials, and
similar materials; wherein said at least one component is adapted
to provide a benefit selected from the group consisting of improved
coke product yields, enhanced coke product adsorption character,
and an alternative use (or recycle) of said at least one
component.
30. A process of hydroprocessing coke, said process comprising:
providing a coke material comprising bonded chemical components
from the group consisting of asphaltenes, resins, and
condensed/polymerized aromatics; and subjecting said coke material
to chemical reactions from the group consisting of hydrogenation
reactions, hydrogenolysis reactions, and cracking reactions via
sufficient time, temperature, pressure, hydrogen, and catalyst
activity to promote cracking and saturation of said coke material
wherein said coke material produces cracked hydrocarbons and
residual coke.
31. The process of claim 30 wherein said residual coke has at least
one characteristic selected from the group consisting of greater
porosity, less coke mass, and lower content of heterocyclic
compounds than said coke material.
32. The process of claim 31 wherein said heterocyclic compounds are
selected from the group consisting of sulfur, nitrogen, oxygen, and
metals.
33. The process of claim 30 wherein said hydrogenation reactions,
said hydrogenolysis reactions, and said cracking reactions are
simultaneous.
34. The process of claim 30 wherein said coke material has
sufficient porosity and internal surface area to provide said
catalyst activity.
35. The process of claim 30 wherein solid-gas phase reactions
sufficiently transfer hydrogen free-radicals in said hydrogenation
reactions, said hydrogenolysis reactions, and said cracking
reactions to reduce hydrogen partial pressure requirements of
solid-liquid-gas phase reactions.
36. The process of claim 30 wherein said coke material is derived
from crude oil.
37. The process of claim 36 wherein said process is promoted in a
delayed coking process between a coking cycle and a decoking
cycle.
38. The process of claim 37 wherein said delayed coking process
utilizes at least 3 coke drums and at least 3 process cycles.
39. The process of claim 37 further comprising hydrotreating liquid
hydrocarbons in at least one time period selected from the group
consisting of before said process and after said process.
40. A process of treating coke, said process comprising: providing
a coke material comprising at least one component selected from the
group consisting of asphaltenes, resins, and condensed/polymerized
aromatics; subjecting said coke material to at least one chemical
extraction reaction via sufficient solvent residence time,
temperature, pressure, and catalytic activity to promote the
removal of said at least one component from said coke material and
to produce a residual coke with greater porosity than said coke
material.
41. The process of claim 40 wherein said at least one chemical
extraction reaction is controlled to promote pore sizes suitable
for predetermined adsorption applications.
42. The process of claim 40 wherein the removal of said at least
one component from said coke material is promoted in a delayed
coking process between a coking cycle and a decoking cycle.
43. The process of claim 42 wherein said delayed coking process
utilizes at least 3 coke drums and at least 3 process cycles.
44. A process of treating coke, said coke comprising: providing a
coke material comprising a porous, carbonaceous content; and
subjecting said coke material to at least one chemical
carbonization reaction via sufficient chemical activator, residence
time, temperature, pressure, and catalytic activity to produce a
residual coke with greater porosity than said coke material.
45. The process of claim 44 wherein said at least one carbonization
reaction is controlled to promote pore sizes suitable for
predetermined adsorption applications.
46. The process of claim 44 wherein said at least one chemical
carbonization reaction is promoted in a delayed coking process
between a coking cycle and a decoking cycle.
47. The process of claim 46 wherein said delayed coking process
utilizes at least 3 coke drums and at least 3 process cycles.
Description
[0001] This application is a continuation-in-part of U.S.
application Ser. No. 09/556,132, filed Apr. 21, 2000, which claimed
the benefit of International Application No. PCT/US99/19091, filed
Aug. 20, 1999, which claimed the benefit of U.S. application Ser.
No. 09/137,283, filed Aug. 20, 1998, now U.S. Pat. No.
6,168,709.
[0002] This application is also a continuation-in-part of U.S.
application Ser. No. 09/763,282, filed Feb. 20, 2001, which claimed
the benefit of International Application No. PCT/US99/19091, filed
Aug. 20, 1999, which claimed the benefit of U.S. application Ser.
No. 09/137,283, filed Aug. 20, 1998, now U.S. Pat. No.
6,168,709.
[0003] The entirety of each of the above priority documents is
hereby incorporated by reference.
BACKGROUND OF THE INVENTION
[0004] 1. Field of the Invention
[0005] This invention relates generally to the field of petroleum
coking processes, and more specifically to modifications of
petroleum coking processes for the production of a premium-quality,
"fuel-grade" petroleum coke. This invention also relates generally
to the use of this new formulation of petroleum coke for the
production of energy, and more specifically to modifications in
conventional, solid-fuel furnaces and environmental control systems
to take optimal advantage of its unique properties.
[0006] 2. Description of Prior Art
[0007] Since initial efforts to refine crude oil in the U.S. during
the late 1800s, the search for an appropriate use for the heaviest
fractions of crude oil (i.e. the "bottom of the barrel") has been a
perplexing problem. Initially, many refineries received little to
no value from the heaviest fractions of crude oil. Some were noted
to simply discard the "bottom of the barrel." Over time, some of
the heavy crude oil fractions were used in asphalt products and
residual fuel oils. However, the demand for these products was not
sufficient to consume increasing production.
[0008] As demand for transportation fuels (e.g. gasoline, diesel,
and aviation fuels) increased in the early 1900s, thermal cracking
processes were developed to convert the heavy crude oil fractions
into lighter products. These refinery processes evolved into the
modern coking processes that predominate the technology currently
used to upgrade the heaviest fractions of the crude oil. These
processes typically reduce the quantity of heavy oil fractions, but
still produce unwanted by-products (e.g. petroleum coke) with
marginal value.
[0009] A. Production of Petroleum Coke; Coking Processes
[0010] In general, modern coking processes employ high-severity,
thermal decomposition (or "cracking") to maximize the conversion of
very heavy, low-value residuum feeds to lower boiling hydrocarbon
products. Coker feedstocks typically consist of non-volatile,
asphaltic and aromatic materials with "theoretical" boiling points
exceeding 1000.degree. F. at atmospheric pressure. The boiling
points are "theoretical" because these materials coke or crack from
thermal decomposition before they reach such temperatures.
[0011] Coking feedstocks normally consist of refinery process
streams which cannot economically be further distilled,
catalytically cracked, or otherwise processed to make fuel-grade
blend streams. Typically, these materials are not suitable for
catalytic operations because of catalyst fouling and/or
deactivation by ash and metals. Common coking feedstocks include
atmospheric distillation residuum, vacuum distillation residuum,
catalytic cracker residual oils, hydrocracker residual oils, and
residual oils from other refinery units. Consequently, coking
feedstocks vary substantially among refineries. Their composition
and quantity primarily depend on (1) the input crude oil blend, (2)
refinery processing equipment, and (3) the optimized operation plan
for any particular refinery. In addition, contaminant compounds,
which occur naturally in the crude oil, generally have relatively
high boiling points and relatively complex molecular structures.
Consequently, these contaminant compounds, containing sulfur and
heavy metals, tend to concentrate in these residua. Many of the
worst process streams in the refinery have become coker feedstock,
and their contaminants usually end up in the petroleum coke
by-product. For this reason, the coking processes have often been
labeled as the "garbage can" of the refinery.
[0012] There are three major types of modern coking processes
currently used in refineries to convert the heavy crude oil
fractions into lighter hydrocarbons and petroleum coke: Delayed
Coking, Fluid Cokin.TM., and Flexicoking.TM.. In all three of these
coking processes, the petroleum coke is considered a by-product
that is tolerated in the interest of more complete conversion of
refinery residues to lighter hydrocarbon compounds, referred to as
"cracked liquids" throughout this discussion. These cracked liquids
range from pentanes to complex hydrocarbons with boiling ranges
typically between 350 and 950.degree. F. The heavier cracked
liquids (e.g. gas oils) are commonly used as feedstocks for further
refinery processing that transforms them into transportation fuel
blend stocks.
[0013] The delayed coking process has evolved with many
improvements since the mid-1930s. Essentially, delayed coking is a
semi-continuous process in which the heavy feedstock is heated to a
high temperature (between 900.degree. F. and 1000.degree. F.) and
transferred to large coking drums. Sufficient residence time is
provided in the coking drums to allow the thermal cracking and
coking reactions to proceed to completion. The heavy residua feed
is thermally cracked in the drum to produce lighter hydrocarbons
and solid, petroleum coke. One of the initial patents for this
technology (U.S. Pat. No. 1,831,719) discloses "The hot vapor
mixture from the vapor phase cracking operation is, with advantage,
introduced into the coking receptacle before its temperature falls
below 950.degree. F., or better 1050.degree. F., and usually it is,
with advantage, introduced into the coking receptacle at the
maximum possible temperature." The "maximum possible temperature"
in the coke drum favors the cracking of the heavy residua, but is
limited by the initiation of coking in the heater and downstream
feed lines, as well as excessive cracking of hydrocarbon vapors to
gases (butane and lighter). When other operational variables are
held constant, the "maximum possible temperature" normally
minimizes the volatile material remaining in the petroleum coke
by-product. In delayed coking, the lower limit of volatile material
in the petroleum coke is usually determined by the coke hardness.
That is, petroleum coke with <8 wt. % volatile materials is
normally so hard that the drilling time in the decoking cycle is
extended beyond reason. Various petroleum coke uses have
specifications that require the volatile content of the petroleum
coke by-product to be <12%. Consequently, the volatile material
in the petroleum coke by-product typically has a target range of
8-12 wt. %. Prior art in the delayed coking process, including
recent developments, has attempted to maximize the production of
cracked liquids with less coke production. In this manner, the
prior art of delayed coking has attempted to minimize coke yield
and the amount of volatile materials it contains.
[0014] Fluid Coking.TM., developed since the late 1950s, is a
continuous coking process that uses fluidized solids to increase
the conversion of coking feedstocks to cracked liquids, and further
reduce the volatile content of the product coke. In Fluid
Coking.TM., the coking feedstock blend is sprayed into a fluidized
bed of hot, fine coke particles in the reactor. Since the heat for
the endothermic cracking reactions is supplied locally by these hot
particles, this permits the cracking and coking reactions to be
conducted at higher temperatures (about 480-565.degree. C. or
900-1050.degree. F.) and shorter contact times than in delayed
coking. Roughly 15-25% of the coke is burned in an adjacent burner
vessel in order to create the hot coke nuclei to contact the feed
in the reactor vessel, and satisfy the process heat requirements.
The Fluid Coking.TM. technology effectively removes the lower limit
of volatile content in the petroleum coke, associated with delayed
coking. The volatile content of the petroleum coke produced by the
Fluid Coking.TM. technology is typically minimized (or reduced),
within the range of 4-10 wt. %. Consequently, the quantity of
petroleum coke, produced by a given feedstock, and its volatile
content are significantly reduced in the Fluid Coking.TM.
technology (vs. delayed coking).
[0015] Flexicoking.TM. is an improvement of the Fluid Coking.TM.
process, in which a third major vessel is added to gasify the
product coke. A coking reactor, a heater (vs. burner) vessel, and a
gasifier are integrated into a common fluidized-solids circulating
system. The "cold coke" from the reactor is partially devolatilized
in the heater vessel. In the gasifier, over 95% of the gross
product coke is gasified to produce either low heating-value fuel
gas or synthesis gas to make liquid fuels or chemicals. In this
manner, the net coke yield is substantially reduced. The purge coke
(.about.5% of the product coke) from the Flexicokin.TM. process
normally contains about 99% of the feed metals and has a volatile
content of 2-7 wt. %.
[0016] Through the years, improvements in the coking processes have
been substantially devoted to increasing the yield and recovery of
cracked liquids and decreasing the coke yield. Thus, the content of
volatile material in the resulting petroleum coke has been
continually decreased, where possible. Various patents disclose
improvements to the delayed coking process that include, but are
not limited to, (1) coker designs that reduce drum pressures (e.g.
25 to 15 psig), (2) coker designs to provide virtually no recycle,
and (3) periodic onstream spalling of heaters to increase firing
capabilities and run length at higher heater outlet temperatures.
These technology advances have been implemented in an effort to
maximize the cracked liquid yields of the delayed coker and reduce
petroleum coke yields and volatile content.
[0017] Other modifications of these coking processes introduce
various wastes for disposal. Several patents disclose various means
to inject certain types of oily sludges. Other prior art uses these
coking processes for the disposal of used lubricating oils.
Additional patents disclose the use of these coking processes for
the disposal of other wastes. In general, these patents discuss the
potential limited impact on the coke yield and volatile content,
and promote other means to negate any increases. Also, these waste
disposal techniques often increase the ash content of the coke and
can introduce additional, undesirable impurities, such as sodium.
Consequently, the objectives of these patents are to reuse or
dispose of these wastes rather than enhance the petroleum coke
properties.
[0018] B. Uses of Petroleum Coke
[0019] The uses of the petroleum coke by-products from these coking
processes depend primarily on its (1) physical properties and (2)
chemical composition (i.e. degree of contamination). The physical
properties (density, crystalline structure, etc.) of the petroleum
coke by-product are determined by various factors, including coking
feedstock blend, coking process and operation, and volatile content
of the coke. The chemical composition and degree of contamination
of the petroleum coke is primarily determined by the composition of
the coking feedstock blend. That is, most of the contaminant
compounds (e.g. sulfur, nitrogen, and various metals) in the
petroleum coke by-product come from heavy, complex chemical
structures in the coking feedstocks, which normally come from the
refinery's crude oil blend. Conversely, the contaminants in the
refinery's crude oil blend ultimately concentrate in the petroleum
coke. Consequently, light, sweet crudes generally have less
contaminants and allow the production of higher value petroleum
coke by-products. However, crude oils are becoming increasingly
heavy and sour, increasing the production of low-grade petroleum
coke.
[0020] Premium and intermediate grades of petroleum cokes have low
to moderate levels of sulfur (e.g. 0.5-2.5%) and heavy metals
(vanadium, nickel, etc.). These grades of coke have various uses as
electrodes and metallurgical carbon in the production of aluminum
and steel. In some applications, the raw petroleum coke is further
processed by calcining to remove volatile material and increase the
coke density. Petroleum coke that cannot meet the required
specifications of these higher-value markets is classified as
"fuel-grade" petroleum coke. As such, this poorest grade of
petroleum coke typically has high concentrations of sulfur
(2.5-5+wt. %) and/or heavy metals, including vanadium and
nickel.
[0021] "Fuel-grade" petroleum coke is actually a misnomer. The
traditional "fuel-grade" petroleum coke actually performs very
poorly as a fuel. First of all, traditional "fuel-grade" petroleum
coke cannot sustain self-combustion due to its poor fuel properties
and combustion characteristics. Secondly, its high sulfur content
(e.g., >2.5 wt. %) creates substantial environmental problems,
particularly in the United States. Thirdly, high concentrations of
certain metals can be precursors for post-combustion, liquid salts
that deposit on heat transfer surfaces, reducing efficiency and/or
causing accelerated corrosion. Finally, high concentrations of
sulfur and/or metals can detrimentally effect product quality, when
used as fuel directly in chemical processes (e.g. concrete kilns).
Consequently, traditional "fuel-grade" petroleum coke can only be
used in conventional furnaces when combined with other fuels (often
requiring separate fuel processing and management systems).
Alternatively, specially designed combustion systems, that are
cumbersome and expensive, can use this coke as fuel. Until these
deficiencies are addressed, the traditional "fuel-grade" petroleum
coke will continue to be a very low value product. In fact,
traditional "fuel-grade" petroleum coke could be classified as a
hazardous waste in the United States, if its value continues its
downward trend and refiners receive no sales value as a product. In
this scenario, costs of hazardous waste disposal could dramatically
reduce refinery profitability, and cause the shutdown of many
refineries across the United States.
[0022] Numerous technologies were apparently developed to modify
coking feedstocks and produce petroleum coke of sufficient quality
for non-fuel uses of higher value. Many patents disclose various
technologies for removing or diluting certain undesirable
contaminants in the petroleum coke. As such, they go far beyond the
degree of decontamination that is required for petroleum coke used
as a fuel. Accordingly, simpler approaches that are less expensive
and less complicated are desirable for the lower level of
decontamination required for petroleum coke used as a fuel.
[0023] Various combustion technologies have been developed to
overcome the deficiencies in "fuel-grade" coke, but no prior art
successfully addresses these problems by upgrading the coke via the
coking process. The prior art has failed to upgrade the quality of
"fuel-grade" petroleum coke sufficiently to use in conventional,
solid-fuel combustion systems (e.g. high heat capacity furnaces
with suspension burners firing pulverized fuel, such as coal).
Specially designed combustion systems (noted above) include
fluidized bed combustion, pyrolysis/gasification systems, and low
heat capacity furnaces (i.e. without heat absorption surfaces). In
general, these systems are cumbersome, expensive, and have
significant problems in scaling size upward. Several patents also
disclose technologies to grind and stabilize coke/oil mixtures for
use in conventional combustion systems. However, the quality of the
traditional petroleum coke used in these fuel mixtures normally
limits (1) the particle size distribution of the solids and (2) the
degree of combustion (i.e. carbon burnout).
[0024] In summary, prior art does not address the major problems
associated with traditional "fuel-grade" petroleum coke:
[0025] 1. There remains a major need to produce "fuel-grade"
petroleum coke that is able to sustain self-combustion with
acceptable combustion efficiencies.
[0026] 2. Secondly, no known prior art satisfactorily resolves the
problems associated with the formation of sticky, corrosive salts
in the combustion process, due to certain contaminants in the
petroleum coke.
[0027] 3. Finally, prior art does exist for the desulfurization and
demetallization of petroleum coke, but it is complicated and
expensive. Simpler approaches are needed for the lower level of
decontamination required for petroleum coke used as a fuel.
OBJECTS AND ADVANTAGES OF THE INVENTION
[0028] Accordingly, it is one object of the present invention to
provide a petroleum coke fuel that is able to (1) sustain
self-combustion with acceptable combustion efficiencies, (2)
sufficiently reduce the corrosive ash deposits harmful to the
combustion system, and/or (3) reduce the need for complicated and
expensive coke decontamination processes and environmental control
systems, including elaborate pollution control equipment in the
combustion system. Other objects and advantages of the present
invention will be readily apparent from the following descriptions
of the drawings and exemplary embodiments.
[0029] The present invention successfully addresses the problems
associated with traditional "fuel-grade" petroleum coke, which
other technologies have failed to do. This invention provides the
following unique features that produce new and unexpected
results:
[0030] 1) Modifications in the coking process provide the ability
to control the quantity and quality of volatile combustible
material (% VCM) in the petroleum coke.
[0031] Acceptable levels of porous, combustible carbon residue in
the product coke (related to the crystalline structure of the coke)
are also assured by these and further modifications. Consequently,
the present invention produces a petroleum coke that is capable of
self-combustion. That is, the upgraded petroleum coke can be
successfully burned in conventional, solid-fuel furnace systems
without auxiliary fuel or the need to mix with other fuels.
[0032] 2) Process modifications reduce quantities of certain salt
and metal contaminants to acceptable levels in the petroleum coke.
These modifications address potentially problematic combustion
products (sticky, corrosive salts) that deposit on downstream heat
exchange and pollution control equipment.
[0033] 3) Combustion process modifications address high sulfur
levels in the petroleum coke that are environmentally prohibitive.
Complicated and expensive desulfurization technologies of the prior
art are not required for petroleum coke decontamination. These
modest combustion process modifications offer a simpler approach to
the control of sulfur oxide and particulate emissions. Similar
process modifications (further embodiments of this invention) can
provide the opportunity to reduce other flue gas emissions,
including nitrogen oxides, carbon dioxide, air toxics, etc. In this
manner, the optimal reductions in particulates, sulfur oxides, and
other undesirable flue gas components can be achieved.
[0034] 1. Utility of the Invention
[0035] The present invention provides a superior "fuel-grade"
petroleum coke for many solid-fuel and/or chemical feedstock
applications while improving overall operations, maintenance, and
profitability in the oil refinery.
[0036] The present invention provides the means to control the
concentrations of volatile combustible material, crystalline
structure, and undesirable contaminants in a manner that produces a
premium, fuel-grade petroleum coke. This upgraded petroleum coke
has qualities that make it superior to the traditional "fuel-grade"
petroleum coke, various types of coals, and other solid fuels. In
most solid fuel applications, these improved characteristics
provide potential users better combustion, higher energy
efficiency, substantially improved pollution control, and
significantly lower operating and maintenance costs. Alternatively,
this premium fuel-grade coke can be partially oxidized via
gasification processes to provide chemical feedstocks or
low-quality, gaseous fuels.
[0037] The present invention produces a high-value product from the
"bottom of the barrel" for many refineries. The present invention
is also less sensitive (compared to prior art) to undesirable
contaminants in the crude oil mixture being processed by a typical
refinery. Consequently, the present invention improves the
flexibility to process various crudes, including low-cost crudes,
that are heavy, sour and/or contain high levels of metals or
asphaltenes. As the world supplies of light, sweet crude decreases,
this benefit has greater utility, since much greater quantities of
"fuel-grade" coke will be produced from the remaining heavy, sour
crude oils. In addition, the process modifications of this
invention are expected to (1) improve operation and maintenance of
the coker process, (2) potentially increase coker and refinery
throughput, and (3) improve other refinery operations. All of these
factors potentially improve the overall refinery profitability.
[0038] Further objects and advantages of this invention will become
apparent from consideration of the drawings and ensuing
descriptions.
SUMMARY OF THE INVENTION
[0039] It has been discovered that an upgraded petroleum coke can
have much better fuel properties and combustion characteristics
than coals with significantly higher (or comparable) levels of
volatile combustible materials (VCM). In addition, the unique
characteristics of this upgraded petroleum coke create the
opportunity for applications of novel environmental control
technologies to meet or exceed environmental requirements.
Surprisingly, these novel and unexpected results can be produced
with modest modifications to the existing coking processes and
combustion systems. However, both the production and use of this
new formulation of petroleum coke are contrary to conventional
wisdom and current trends in the petroleum coking processes and
solid fuel combustion systems.
[0040] 1. Coking Processes
[0041] Conventional wisdom and current trends in the petroleum
coking processes focus on coking designs and operations that (1)
maximize the production and recovery of cracked liquid hydrocarbons
and (2) minimize the level of volatile combustible material in the
resulting coke. In contrast, the modified coking process of the
present invention gives priority to producing a petroleum coke with
consistently higher volatile combustible material of sufficient
quality for self-combustion. This modified process also promotes a
coke crystalline structure that is more conducive to good
combustion. In many cases, low-level decontamination of the
petroleum coke to acceptable levels is also achieved to eliminate
(or reduce) the formation of corrosive ash deposits in the
combustion process. Surprisingly, the present invention, in all its
embodiments, can produce a premium, "fuel-grade" petroleum coke,
capable of self-combustion with superior fuel properties and
combustion characteristics, while decreasing cracked liquid
conversion efficiency by <10% (preferably <1%). The present
invention discusses various means to offset (or limit) the loss of
cracked liquid yield. In certain situations, the present invention
can upgrade the petroleum coke fuel, while actually increasing
overall cracked liquids production, due to potential increases in
coker and/or refinery throughput.
[0042] In general terms, the invention includes a process of
producing a coke fuel, the method comprising steps: (a) obtaining a
coke precursor material derived from crude oil, and having a
volatile organic component; and (b) subjecting the coke precursor
material to a thermal cracking process for sufficient time and at
sufficient temperature and under sufficient pressure so as to
produce a coke product having a volatile combustible material (VCM)
present in an amount in the range of from about 13% to about 50% by
weight. Most preferably, the volatile combustible material in the
coke product typically may be in the range of from about 15% to
about 30% by weight. The thermal cracking process of the present
invention may include a process selected from the group consisting
of delayed coking processes and Fluid Coking.TM. processes. As used
herein, "volatile combustible material" (VCM) is defined by ASTM
Method D 3175. In the present invention, all the VCM is contained
in the coke precursor material derived from crude oil or added to
the coking process; as contrasted with any substantial volatile
organic component (e.g. fuel oil) that has been added to a coke
product after the coking process is complete.
[0043] In some cases, a consistently higher VCM level will be all
that is necessary to provide petroleum coke capable of
self-combustion. Process controls of the prior art typically
minimize VCM in the by-product petroleum coke. That is, coking
units in the prior art typically have operational setpoints to
produce by-product petroleum coke with VCM levels below 12%. In
contrast, the present invention discusses various means to increase
and consistently maintain higher coke VCM levels for various coking
processes, including delayed and Fluid Coking.TM. processes. A
"minimum acceptable" VCM specification (e.g. >15% VCM) is
discussed as an exemplary means of maintaining product quality.
[0044] In many cases, altering the petroleum coke crystalline
structure will also be required to produce petroleum coke capable
of self-combustion. In most (but not all) cases, altering the
crystalline structure will enhance combustion characteristics and
reduce the "minimum-acceptable" VCM specification. The present
invention discusses various means to promote favorable coke
crystalline structure. In an exemplary embodiment, the coker
process changes that increase and consistently maintain the desired
VCM level also promote greater production of the more desirable
sponge coke (vs. shot coke or needle coke). That is, the organic
compounds, creating the higher VCM in the coke, are expected to
alter the coke formation mechanisms (i.e. thermal vs. asphaltic
coke) to favor sponge coke production. The sponge coke crystalline
structure is preferable due to higher porosity and softness, which
greatly improve its combustion characteristics. Further embodiments
are provided to inhibit the formation of undesirable dense,
spherical coke, called "shot coke." Consequently, the present
invention promotes sponge coke crystalline structure that favors
good combustion and maintains acceptable levels of shot coke . A
"minimum-acceptable" sponge coke specification is discussed as one
means of maintaining coke crystalline quality. That is, process
control methods will consistently achieve a coke crystalline
structure that preferably contains 40-100% sponge coke (vs. shot
coke); most preferably 60-100% sponge coke (vs. shot coke).
Alternatively, a "maximum-acceptable" shot coke specification or a
specification for average coke density (e.g. gm/cc) can provide
alternative measures for process control of a particular coker
design and feedstock.
[0045] In other cases, the addition of higher quality VCM (e.g. VCM
with boiling points of about 250-850.degree. F. and heating values
of 16-20,000 Btu/lb) may be necessary to produce petroleum coke
capable of self-combustion. Alternatively, higher quality VCM in
the petroleum coke can be used to reduce the overall VCM
specification (i.e. minimum-acceptable VCM). The present invention
discusses various means to add higher quality VCM within the coking
process, and achieve uniform integration within the coke. In this
manner, a softer coke crystalline structure with higher porosity is
maintained, while further improving the upgraded coke's combustion
characteristics.
[0046] In many (but not all) cases, low-level decontamination of
the petroleum coke may be necessary to assure acceptable levels of
sulfur, sodium, and other metals for the combustion process. In an
exemplary embodiment, the coke precursor material is subjected to
an efficient desalting process prior to the thermal cracking
process to reduce the concentration of certain undesirable
contaminants in the upgraded petroleum coke. An exemplary desalting
method uses three stages of conventional, refinery desalting
processes. Alternatively, filtration, catalytic, and other
efficient desalting methods can be used. Any of these desalting
processes will remove various contaminants to various degrees.
However, sodium is the contaminant of primary concern to prevent
problematic ash products (e.g. sticky, corrosive salts) from the
combustion of most "fuel-grade" petroleum coke. The coke precursor
material preferably will contain less than 15 ppm by weight sodium,
and most preferably less than 5 ppm by weight sodium. Further
embodiments of the present invention describe other means for
achieving sodium, sulfur, and metals decontamination objectives
noted above. Desulfurization and demetallization embodiments are
discussed as alternatives to enhance environmental control options
and also improve the prevention of problematic ash products.
[0047] 2. Solid Fuel Combustion Systems
[0048] Conventional wisdom and current trends of solid-fuel
combustion systems are moving toward further use of traditional,
"fuel-grade" petroleum coke as (1) a periodic "spiking" fuel, (2)
continual use in coal/coke fuel blends, or (3) primary fuel in
complex, specially designed combustion systems. In the first two
cases, traditional petroleum coke typically makes up less than 20%
of the blend and often requires a separate fuel preparation system.
In contrast, the present invention produces a Premium "Fuel-Grade"
Petroleum Coke that has great value as a replacement for various
solid fuels, including numerous coals. The primary use is expected
to be a direct replacement of various coals in existing coal-fired
boilers (utility, industrial, or otherwise). That is, the present
invention includes a new formulation of coke product made in
accordance with a process according to the present invention, in
all of its embodiments. The present invention also includes a
method for producing energy, the method comprising generally
combusting a fuel, the fuel comprising coke, the coke comprising
volatile combustible material (VCM) in an amount in the range from
about 13% to about 50% by weight. Preferably, the volatile
combustible material in the coke is in the range from about 15% to
about 30% by weight.
[0049] A method of the present invention also includes a method of
producing energy using a fuel that comprises mixtures of the
upgraded coke of the present invention, and other fuels, including
coke and solid fuels (e.g. coal), or coke and liquid fuels (e.g.
fuel oil), or coke and gaseous fuels (e.g. natural gas) or any
combination of these; and preferably consisting essentially of the
upgraded coke of the present invention as described herein. Where
the coke is mixed with coal, it may be preferred that the weight
ratio of coke to coal in said mixture be greater than about 1:4.
Alternatively, the method of producing energy in accordance with
the present invention may feature a heat release rate of the coke
in such a fuel mixture greater than 20%. However, it may be
preferred that the fuel comprises the upgraded coke including
volatile combustible material in an amount in the range from about
13% to about 50% by weight, most preferably in the range of about
15% to about 30% by weight. Consequently, the method of the present
invention allows for the achievement of optimal combustion
properties while also allowing the control of costs.
[0050] Conventional wisdom and current trends of environmental
controls for solid-fuel combustion systems is moving toward (1)
low-sulfur energy sources (solid-fuels and otherwise), (2)
extensive system modifications to add complex, expensive
environmental controls, and (3) repowering conversions to
alternative energy technologies with lower environmental emissions.
Many coal-fired, utility boilers have been switched to low-sulfur
coal to comply with the first phase of acid rain control provisions
under the Clean Air Act Amendments of 1990. Complex, expensive
environmental controls and repowering options are being evaluated
for compliance in Phase 2.
[0051] In contrast, the method of the present invention may
optionally and preferably include a method for producing energy, as
described, and a method for removing sulfur oxides and/or other
undesirable components from its flue gas. The present invention
uses novel techniques to burn the premium, "fuel-grade" petroleum
coke with higher sulfur content and obtain lower sulfur oxide
emissions. The unique properties of the upgraded petroleum coke
allow it to be used as the primary fuel in existing, pulverized
coal boilers. In most cases, use of the upgraded petroleum coke as
the primary fuel, unleashes >90% of the capacity in the existing
particulate control device (PCD), due to its much lower ash
content. In these applications, the existing particulate control
devices can be readily converted to emissions control systems that
provide sufficient control of sulfur oxides (SOx), carbon dioxide,
nitrogen oxides (NOx), air toxics, and/or other undesirable flue
gas components. The method for removing undesirable components (1)
converts the undesirable components to collectible particulates
upstream of the existing PCD and (2) collects such particulates in
the existing particulate control device. That is, the method of the
present invention for producing energy further includes a method
for removing undesirable flue gas components. This method generally
comprises (1) an injection of conversion reagents with sufficient
mixing and sufficient residence time at sufficient temperature to
convert undesirable flue gas components to collectible particulates
upstream of a particulate control device (PCD) and (2) collecting
said particulates in particulate control device, said particulate
control device includes, but is not limited to, a PCD process
selected from the group consisting of electrostatic precipitators
(dry or wet), filtration, cyclones, and conventional wet
scrubbers.
[0052] In one embodiment, the unreacted conversion reagents of this
flue gas conversion process can be effectively recycled to increase
reagent utilization and performance. The recycle rate preferably
exceeds 5% by weight of the collected flyash. This level of reagent
recycle is a unique feature of this flue gas conversion process,
due to the fuel properties and combustion characteristics of the
upgraded coke.
[0053] In another embodiment, the spent flue gas conversion
reagents can be regenerated and reused. The regeneration rate can
exceed 70% by weight of the collected flyash, and preferably less
than 30% of the collected fly ash is disposed as a purge (or
blowdown) stream, containing high concentrations of impurities. The
regeneration method includes, but is not limited to, a process
selected from the group of hydration, precipitation, and other unit
operations. The purge stream can be used as a resource for valuable
metals, which are extracted and purified. This type of reagent
regeneration can (1) substantially decrease reagent make-up
requirements and costs, (2) dramatically reduce flyash disposal and
costs, (3) reduce CO.sub.2 emissions, (4) create a resource for
valuable metals, and (5) provide the means to economically improve
the flue gas conversion process via the use of more reactive
reagents. The regeneration of conversion reagents is a unique
feature of this flue gas conversion process, due to the fuel
properties and the combustion characteristics of the upgraded
coke.
[0054] For SOx removal, the flue gas conversion process of the
present invention is similar to dry sorbent injection and dry
scrubber technologies, but has novel improvements due to the unique
properties of the upgraded petroleum coke of the present invention.
In addition to the recycling and regeneration of reagents noted
above, these novel improvements include increased reagent
reactivity, improved reagent utilization, shorter residence times,
and greater opportunity for salable products. All of these
improvements over the prior art increase SOx removal efficiencies
and reduce costs.
[0055] The present invention also discusses embodiments to
integrate and/or optimize various environmental control techniques.
The flue gas conversion process may be used in coordination with
traditional wet or dry SOx scrubbing systems to improve or optimize
control of various undesirable flue gas components. Also, upgraded
cokes with low sulfur content (e.g. sweet crude feedstocks, coker
feedstock desulfurization, etc.) can provide greater flexibility in
the use of the available PCD capacity (i.e. other than SOx).
Furthermore, the integration of activated coke technology is also
discussed for the combined control of SOx, NOx, carbon dioxide and
air toxics.
[0056] In the practical application of the present invention, the
optimal combination of methods and embodiments will vary
significantly. That is, site-specific, design and operational
parameters of the particular coking process and refinery must be
properly considered. These factors include (but should not be
limited to) coker design, coker feedstocks, and effects of other
refinery operations. In addition, site-specific, design and
operational parameters of the particular solid-fuel combustion
system and its environmental controls must be properly considered.
These factors include (but should not be limited to) combustion
system design, current fuel characteristics, design of
environmental controls, and environmental requirements.
Consequently, case-by-case analyses (often including pilot plant
tests) are required to address site-specific differences in the
optimal application of the present invention. The present invention
discusses methods to optimize the production and use of the
upgraded petroleum coke for each particular application.
BRIEF DESCRIPTION OF DRAWINGS
[0057] FIG. 1 shows a basic process flow diagram for key elements
of a traditional delayed coking process.
[0058] FIG. 2 shows a basic process flow diagram for a
conventional, coal-fired utility boiler with traditional
particulate control device (PCD): Baghouse, electrostatic
precipitator (ESP), or other. In this case, the combustion system
has been modified to include reaction vessel(s) and/or reagent
injection system(s) for control of undesirable flue gas
components.
[0059] FIG. 3 shows comparisons of burning profiles for existing
coals and traditional petroleum coke.
[0060] FIG. 4 shows a basic process flow diagram for key elements
of a traditional Fluid Coking.TM. process.
[0061] FIG. 5 shows a basic process flow diagram for a
conventional, coal-fired utility boiler with a wet scrubber
downstream of the traditional particulate control device (PCD):
Baghouse, electrostatic precipitator (ESP), or other. The
combustion system has been modified to include a reaction vessel(s)
and/or reagent injection system(s) for control of undesirable flue
gas components.
[0062] FIG. 6A shows a cross sectional view of an exemplary basic
equipment diagram of a coke drum having a side-draw vapor line
wherein the coke drum is adapted for injection of certain media to
thermally quench the vapors exiting the coke drum during the coking
cycle of the delayed coking process. The existing coke drum(s) have
been modified with reinforced flanges for quench media lances that
can be removed for maintenance, as needed.
[0063] FIG. 6B shows a partial top plan view of the coke drum of
FIG. 6A.
[0064] FIG. 6C shows a cross sectional view of an exemplary basic
equipment diagram of a coke drum having a center-draw vapor line
wherein the coke drum is adapted for injection of certain media to
thermally quench the vapors exiting the coke drum during the coking
cycle of the delayed coking process. The existing coke drum(s) have
been modified with reinforced flanges for quench media lances that
can be removed for maintenance, as needed.
[0065] FIG. 6D shows a partial top plan view of the coke drum of
FIG. 6C.
[0066] FIG. 6E shows a cross sectional view of an exemplary basic
equipment diagram of a coke drum having a side-draw vapor line
wherein the coke drum is adapted for injection of certain media via
a vertical spray in the vapor line to thermally quench the vapors
exiting the coke drum during the coking cycle of the delayed coking
process.
[0067] FIG. 6F shows a partial top plan view of the coke drum of
FIG. 6E.
[0068] FIG. 6G shows a cross sectional view of an exemplary basic
equipment diagram of a coke drum having a side-draw vapor line
wherein the coke drum is adapted for injection of certain media via
a horizontal spray in the vapor line to thermally quench the vapors
exiting the coke drum during the coking cycle of the delayed coking
process.
[0069] FIG. 6H shows a partial top plan view of the coke drum of
FIG. 6G.
[0070] FIG. 7A shows a cross sectional view of a basic equipment
diagram for a modified drill stem to inject media that thermally
and/or chemically quenches excessive cracking reactions in the
vapor phase during the coking cycle of the delayed coking process.
This equipment may serve the purpose of quenching heavy vapors
exiting the coke drum in a manner similar to the equipment in FIGS.
6A through 6H. The existing drill stem, coke drum derrick, and coke
drum center flange have been modified for injection of certain
agents in the coking cycle, while maintaining the ability to use
the existing drill stem to cut coke from the drum in the decoking
cycle.
[0071] FIG. 7B shows a cross sectional view of an exemplary
sealing. mechanism (i.e., an internal double mechanical seal) for
the modified head flange of FIG. 7A in this high-pressure
operation.
[0072] FIG. 8 shows an exemplary process flow diagram for a delayed
coking system with three coke drums. This delayed coker has been
modified to provide three process cycles: coking, coke treatment,
and decoking cycles. The coke quench is completed during the last
two cycles.
[0073] FIG. 9 shows an exemplary operating conditions diagram for
petroleum coke hydroprocessing. Three zones of different operating
approaches are demonstrated.
DETAILED DESCRIPTION OF THE EXEMPLARY EMBODIMENT(S)
[0074] In view of the foregoing summary, the following presents a
detailed description of the exemplary embodiments of the present
invention, currently considered the best mode of practicing the
present invention. The discussion of the exemplary embodiments is
divided into two major subjects: (1) the production of premium
"fuel-grade" petroleum coke in a modified delayed coking process,
and (2) the use of this petroleum coke in conventional,
pulverized-coal (PC) utility boilers. Example I is provided at the
end of this discussion to illustrate an exemplary embodiment of the
present invention.
[0075] 1. Production of Premium "Fuel-Grade" Petroleum Coke:
Modified Delayed Coking Process
[0076] The discussion of the production of premium, "fuel-grade"
petroleum coke in a modified delayed coking process is divided into
the following topics: (a) traditional delayed coking: process
description, (b) process control of the prior art, (c) coke
formation mechanisms and various crystalline structures, (d)
volatile combustible materials (VCM) in the petroleum coke, (e)
process control of the present invention (VCM and crystalline
structure), (f) low-level decontamination of coker feedstocks:
3-stage desalting operation, and (g) impacts of the present
invention on refinery operations.
[0077] A. Traditional Delayed Coking: Process Description
[0078] FIG. 1 is a basic process flow diagram for the traditional
delayed coking process of the prior art. The delayed coking process
equipment for the present invention is essentially the same, but
the operation, as discussed below, is substantially different.
Delayed coking is a semi-continuous process with parallel coking
drums that alternate between coking and decoking cycles.
[0079] In the coking cycle, coker feedstock is heated and
transferred to the coke drum until full. Hot residua feed 10 is
introduced into the bottom of a coker fractionator 12, where it
combines with condensed recycle. This mixture 14 is pumped through
a coker heater 16, where the desired coking temperature (normally
between 900.degree. F. and 950.degree. F.) is achieved, causing
partial vaporization and mild cracking. Steam or boiler feedwater
18 is often injected into the heater tubes to prevent the coking of
feed in the furnace. Typically, the heater outlet temperature is
controlled by a temperature gauge 20 that sends a signal to a
control valve 22 to regulate the amount of fuel 24 to the heater. A
vapor-liquid mixture 26 exits the heater, and a control valve 27
diverts it to a coking drum 28. Sufficient residence time is
provided in the coking drum to allow the thermal cracking and
coking reactions to proceed to completion. By design, the coking
reactions are "delayed" until the heater charge reaches the coke
drums. In this manner, the vapor-liquid mixture is thermally
cracked in the drum to produce lighter hydrocarbons, which vaporize
and exit the coke drum. The drum vapor line temperature 29 (i.e.
temperature of the vapors leaving the coke drum) is the measured
parameter used to represent the average drum temperature. Petroleum
coke and some residuals (e.g. cracked hydrocarbons) remain in the
coke drum. When the coking drum is sufficiently full of coke, the
coking cycle ends. The heater outlet charge is then switched from
the first coke drum to a parallel coke drum to initiate its coking
cycle. Meanwhile, the decoking cycle begins in the first coke
drum.
[0080] In the decoking cycle, the contents of the coking drum are
cooled down, remaining volatile hydrocarbons are removed, the coke
is drilled from the drum, and the coking drum is prepared for the
next coking cycle. Cooling the coke normally occurs in three
distinct stages. In the first stage, the coke is cooled and
stripped by steam or other stripping media 30 to economically
maximize the removal of recoverable hydrocarbons entrained or
otherwise remaining in the coke. In the second stage of cooling,
water or other cooling media 32 is injected to reduce the drum
temperature while avoiding thermal shock to the coke drum.
Vaporized water from this cooling media further promotes the
removal of additional vaporizable hydrocarbons. In the final
cooling stage, the drum is quenched by water or other quenching
media 34 to rapidly lower the drum temperatures to conditions
favorable for safe coke removal. After the quenching is complete,
the bottom and top heads of the drum are removed. The petroleum
coke 36 is then cut, typically by hydraulic water jet, and removed
from the drum. After coke removal, the drumheads are replaced, the
drum is preheated, and otherwise readied for the next coking
cycle.
[0081] Lighter hydrocarbons 38 are vaporized, removed overhead from
the coking drums, and transferred to a coker fractionator 12, where
they are separated and recovered. Coker heavy gas oil (HGO) 40 and
coker light gas oil (LGO) 42 are drawn off the fractionator at the
desired boiling temperature ranges: HGO: roughly 650-870.degree. F;
LGO: roughly 400-650.degree. F. The fractionator overhead stream,
coker wet gas 44, goes to a separator 46, where it is separated
into dry gas 48, water 50, and unstable naphtha 52. A reflux
fraction 54 is often returned to the fractionator.
[0082] In general, delayed coking is an endothermic reaction with
the furnace supplying the necessary heat to complete the coking
reaction in the coke drum. The exact mechanism of delayed coking is
so complex that it is not possible to determine all the various
chemical reactions that occur, but three distinct steps take
place:
[0083] 1. Partial vaporization and mild cracking of the feed as it
passes through the furnace
[0084] 2. Cracking of the vapor as it passes through the coke
drum
[0085] 3. Successive cracking and polymerization of the heavy
liquid trapped in the drum until it is converted to vapor and
coke
[0086] B. Process Control of the Prior Art
[0087] In traditional delayed coking, the optimal coker operating
conditions have evolved through the years, based on much experience
and a better understanding of the delayed coking process. Operating
conditions have normally been set to maximize (or increase) the
efficiency of feedstock conversion to cracked liquid products,
including light and heavy coker gas oils. More recently, however,
the cokers in some refineries have been changed to maximize (or
increase) coker throughput. In both types of operation, the quality
of the byproduct petroleum coke is a relatively minor concern. In
"fuel-grade" coke operations, either mode of operation
detrimentally affects the fuel properties and combustion
characteristics of the coke, particularly VCM content and
crystalline structure.
[0088] In general, the target operating conditions in a traditional
delayed coker depend on the composition of the coker feedstocks,
other refinery operations, and coker design. Relative to other
refinery processes, the delayed coker operating conditions are
heavily dependent on the feedstock blends, which vary greatly among
refineries (due to varying crude blends and processing scenarios).
The desired coker products and their required specifications also
depend greatly on other process operations in the particular
refinery. That is, downstream processing of the coker liquid
products typically upgrades them to transportation fuel components.
The target operating conditions are normally established by linear
programming (LP) models that optimize the particular refinery's
operations. These LP models typically use empirical data generated
by a series of coker pilot plant studies. In turn, each pilot plant
study is designed to simulate the particular refinery's coker
design. Appropriate operating conditions are determined for a
particular feedstock blend and particular product specifications
set by the downstream processing requirements. The series of pilot
plant studies are typically designed to produce empirical data for
operating conditions with variations in feedstock blends and liquid
product specification requirements. Consequently, the coker designs
and target operating conditions vary significantly among
refineries.
[0089] In common operational modes, various operational variables
are monitored and controlled to achieve the desired delayed coker
operation. The primary independent variables are feed quality,
heater outlet temperature, coke drum pressure, and fractionator hat
temperature. The primary dependent variables are the recycle ratio,
the coking cycle time and the drum vapor line temperature. The
following target control ranges are normally maintained during the
coking cycle for these primary operating conditions:
[0090] 1. Heater outlet temperatures in the range of about
900.degree. F. to about 950.degree. F.,
[0091] 2. Coke drum pressure in the range of about 15 psig to 100
psig: typically 20-30 psig,
[0092] 3. Hat Temperature in the range of 650-720.degree. F:
typically 670 to 700.degree. F.
[0093] 4. Recycle Ratio in the range of 0-100%; typically
10-20%,
[0094] 5. Coking cycle time in the range of about 15 to 24 hours;
typically 18-24 hours, and a
[0095] 6. Drum Vapor Line Temperature 50 to 100.degree. F. less
than the heater outlet temperature: range 825 to 880.degree. F.;
typically 830 to 860.degree. F.
[0096] These traditional operating variables have primarily been
used to control the quality of the cracked liquids and various
yields of products, with minor attention to controlling the
respective composition of the by-product petroleum coke. Throughout
this discussion, "cracked liquids" refers to hydrocarbon products
of the coking process that have 5 or more carbon atoms. They
typically have boiling ranges between 97 and 870.degree. F, and are
liquids at standard conditions. Most of these hydrocarbon products
are valuable transportation fuel blending components or feedstocks
for further refinery processing. Consequently, cracked liquids are
normally the primary objective of the coking process.
[0097] Since the mid-1930s, better understanding of the delayed
coking process and technological advances have continually
maximized (or increased) the efficiency of feedstock conversion.
Feedstock conversion is often cited as liquid yield (i.e. barrel of
cracked liquid product per barrel of feed). Increasing the yield of
cracked liquids is generally accomplished by changing the operating
conditions to affect (1) the balance between cracking and coking
reactions and/or (2) the vaporization and recovery of the cracked
liquid products. Though the specific operating conditions vary
among refineries, the following rules of thumb have been noted as
guidelines for reductions in coke yield, and associated increases
in the yield of cracked liquids:
[0098] 1. Each 10.degree. F. increase in coke-drum vapor line
temperature reduces coke yield on feed by 0.8 wt. % and increases
gas and distillates by 1.1 volume% on feed
[0099] 2. Each 8 psi reduction in the coke drum pressure reduces
the coke yield on feed by 1.0 wt. % and increases liquid yield by
1.3 volume % on feed
[0100] 3. Reducing the recycle by 10 vol.% on feed reduces the coke
yield by 1.2 wt. % on feed and increases the liquid plus gas yield
by 1.0 vol.% onfeed
[0101] 4. Reducing the virgin gas oil content of the coker feed by
10% reduces coke yield by 1.5 wt. %
[0102] Technology advances have also been implemented in the effort
to maximize the liquid yields of the delayed coker. These include,
but are not limited to, (1) coker designs to reduce drum pressure
to 15 psig, (2) coker designs to provide virtually no recycle, and
(3) periodic onstream spalling of heaters to increase firing
capabilities and run length at higher heater outlet
temperatures.
[0103] Over the past ten years, some refineries have switched coker
operating conditions to maximize (or increase) the coker
throughput, instead of maximum efficiency of feedstock conversion
to cracked liquids. Due to processing heavier crude blends,
refineries often reach a limit in coking throughput that limits (or
bottlenecks) the refinery throughput. In order to eliminate this
bottleneck, refiners often change the coker operating conditions to
maximize (or increase) coker throughput in one of two ways:
[0104] 1. If the coker is fractionator (or vapor) limited, increase
the drum pressure (e.g., 20 to 25 psig.)
[0105] 2. If the coker is drum (or coke make) limited, reduce
coking cycle time (e.g., 20 to 16 hours)
[0106] Both of these operational changes increase the coker
throughput. Though either type of higher throughput operation
reduces the efficiency of feedstock conversion to cracked liquids
(i.e. per barrel of feed basis), it often maximizes (or increases)
the overall quantity (i.e. barrels) of cracked liquids produced.
These operational changes also tend to increase coke yield and coke
VCM, as noted previously. However, any increase in drum pressure or
decrease in coker cycle time is usually accompanied by a
commensurate increase in heater outlet and drum vapor line
temperatures to offset (or limit) any increases in coke yield or
VCM.
[0107] The current trend in delayed coking includes capital
improvements to the original coker design to eliminate bottlenecks
and maximize (or increase) both Coker liquid yields and coker
throughput, to the extent possible. Limits on coke heaters, coke
drums, and fractionators are removed by employing equipment
modifications that incorporate technology advancements. These
modifications will normally address the refinery's projected coker
feedstock composition and quantity. The timing of these
modifications is likely to depend on many factors, including (1)
justification via the loss of cracked liquids to increased coke
yields, and (2) the refinery's capital investment criteria (e.g.,
alternative projects and higher operational risk factors, such as
increased environmental regulations).
[0108] In both types of process control in the prior art, the VCM
content of the byproduct coke is used mostly as a post-mortem gauge
of successful operation, NOT as an essential operational variable.
The coke VCM is measured after the batch operation is complete.
Pilot plant studies are used to predict the coke VCM for a
particular set of operating conditions, feedstock, and coker
design. However, the scaled-up commercial operation may stray from
target VCM levels, due to less than ideal conditions. If needed,
adjustments in operating conditions are usually made based on
experience for future coking batches. Typically, the target
operating range for coke VCM in delayed coking is 8-12 wt. %. If
the coke VCM is lower than 8 wt. %, the coke is usually too hard to
cut from the drum within the normal decoking cycle time. A coke VCM
greater than 12 wt. % is normally considered poor conversion
efficiency. Also, some grades of anode and needle coke have a
maximum VCM product specification (typically <12 wt. %) that
assures proper density characteristics. Accordingly, the normal
operating conditions for both maximum conversion and maximum
throughput modes are continually modified to achieve the lowest
possible coke VCM in the long-term, with acceptable coker
operation. Consequently, the process control options of the prior
art detrimentally impact the fuel properties and combustion
characteristics of "fuel-grade" coke. That is, the coke VCM content
and/or crystalline structure of the by-product coke are not
normally sufficient to sustain self-combustion.
[0109] Delayed coker process controls of the prior art (i.e.
maximum conversion and/or maximum throughput) also tend to promote
the production of undesirable coke crystalline structure. These
operating conditions typically promote the formation of shot coke,
particularly for heavy feedstocks. In some refineries, sponge coke
can predominate shot coke. However, the sponge coke in this
shot/sponge coke blend will tend to have low porosity due to its
low VCM. This latter outcome is more likely with the operating
conditions that maximize coker throughput. In either operational
mode of the prior art, the byproduct coke tends to have crystalline
structures of shot coke and/or sponge coke with low porosity and
low VCM. As discussed later, these crystalline structures are not
desirable for good combustion characteristics.
[0110] In conclusion, the operating conditions of the prior art
give first priority to maximizing the efficiency of feedstock
conversion to cracked liquid products or maximizing coker
throughput. In either case, the petroleum coke is a byproduct that
is tolerated in the interest of the maximum production of cracked
liquid hydrocarbons, barrel per barrel of feed or total barrels.
The VCM content and crystalline structure of the resultant coke is
a relatively minor concern (by comparison), especially for
"fuel-grade" petroleum coke. As such, the process control of the
prior art is not conducive to produce a high-quality, "fuel-grade"
coke.
[0111] C. Coke Formation Mechanisms and Various Crystalline
Structures
[0112] Coking processes, in general, are high-severity, thermal
cracking (or destructive distillation) operations to convert
petroleum residua into distillates, hydrocarbon gases, and coke.
The residua feed is typically heated to temperatures exceeding
900.degree. F. Thermal decomposition of the high-molecular,
hydrocarbon structures takes place in both the liquid and gaseous
phases. The breaking of chemical bonds in the liquid phase
typically produces lighter hydrocarbon compounds that vaporize
below the drum temperature (e.g. <870.degree. F.). The remaining
liquids (normally complex hydrocarbon structures with highly
aromatic content) polymerize to form coke. Thermal decomposition
will continue in the gaseous phase (producing lighter and lighter
compounds) until there is not sufficient activation energy to
initiate the endothermic cracking reaction. The cracking and coking
reactions occur simultaneously, and their degrees of completion
primarily depend on the temperature, residence time, and pressure
in the reaction system. The remainder of this discussion primarily
focuses on the thermal cracking of the liquid phase and the
subsequent formation of coke.
[0113] The formation of coke in the delayed coking process occurs
primarily by two independent coking mechanisms: Thermal Coke and
Asphaltic Coke. The thermal coking mechanism is caused by an
endothermic reaction: the condensation and polymerization of
aromatic compounds contained in the petroleum residue of the coker
feed. This thermal coke mechanism is substantially reduced by
operating conditions (e.g. higher operating temperatures) that
increase the production of cracked liquid hydrocarbons. The
asphaltic coke mechanism is initiated as solutizing oils are
removed by thermal cracking and aromatic cross-linkage from the
coker charge. The large asphaltene and resin molecules precipitate
out of solution to form a solid without much change in structure.
The asphaltic coke mechanism (1) is a physical change with no heat
of reaction, (2) is not affected by modified coker operating
conditions, and (3) is purely a function of the asphaltene and
resin content in the coker feedstock. The relative degrees of these
two coking mechanisms have been noted to determine the crystalline
structure of the delayed coke.
[0114] Petroleum coke from a delayed coker has three major types of
crystalline structure: needle coke, sponge coke, and shot coke.
Needle coke is formed via virtually all thermal coke mechanism:
>95% of the coke from the condensation and polymerization of
aromatics contained in a low-asphaltene coker feedstock (e.g. FCC
slurry oil). Sponge coke and shot coke are formed by combinations
of thermal and asphaltic coking mechanisms. When the ratio (R) of
asphaltic coke to thermal coke falls below a certain level, sponge
coke is formed. Conversely, when R exceeds a certain level, shot
coke is formed. This ratio R is difficult to measure. Furthermore,
the boundary between shot coke and sponge coke is not definite, but
fuzzy, and is expected to vary with coker feedstocks. In fact, the
combination of shot coke and sponge coke has been noted to form in
the same coking cycle due to temperature variations across the coke
drum. However, limited plant data suggest the crossover point for
shot (vs. sponge) coke formation is roughly R>0.7-1.5;
preferably 0.8 to 1.2.
[0115] D. Volatile Combustible Materials (VCM) in the Petroleum
Coke
[0116] Many in the oil refining industry surprisingly believe that
virtually all of the volatile material in the petroleum coke is
valuable, cracked liquids trapped in the coke. This mistaken belief
apparently occurs due to a major difference in the definition of
"volatile materials" for the oil refining industry versus
combustion science. The oil refining industry commonly refers to
non-volatile, asphaltic and aromatic materials, contained in the
coker feedstocks, as 1000 plus materials, which have "theoretical"
boiling points exceeding 1000 F. at atmospheric pressure. The
boiling points are "theoretical" because these materials crack or
coke from thermal decomposition before they reach such
temperatures. As such, the oil refining industry considers
materials with boiling points <1000.degree. F. as "volatile
materials." In contrast, combustion science (via ASTM Test Method
D-3175) defines volatile combustible materials (VCM) as the weight
percent of the fuel that is vaporized at temperatures less than
950.degree. C. (1742.degree. F.). Therefore, materials that are
vaporized between 1000.degree. F. and 1742.degree. F. are
considered volatile materials by combustion science, but not by the
oil refining industry, in general. Consequently, the VCM in the
petroleum coke is expected to be a combination of:
[0117] (1) unreacted coker feedstocks that vaporize between residua
BP Cutpoints (e.g. 1000.degree. F.) and 1742.degree. F.;
[0118] (2) cracked components that vaporize between drum
temperature (e.g. 870.degree. F.) and 1742.degree. F; and
[0119] (3) cracked components that vaporize below drum temperature
(e.g. 870.degree. F.) trapped in the coke.
[0120] Since steam stripping of the porous petroleum coke is
typically conducted for 1 to 3 hours in the decoking cycle, the VCM
of traditional coke is expected to consist mostly of (1) and (2).
However, under certain conditions, the coke VCM may have weak
chemical bonds to the coke that prevent steam stripping. The
activation energies required to break these weak chemical bonds can
be provided by the initial phases of combustion or ASTM Method D
3175. Note: The drum temperatures for the cracked components of (2)
and (3) need to be adjusted for drum pressures to determine
comparable boiling points at equivalent conditions. Throughout this
patent application, "volatile combustible materials" or "VCM" will
refer to volatile combustible materials as defined by the American
Society for Testing and Materials (ASTM) Method D 3175. This method
stipulates a temperature of 950+/20.degree. C. for seven minutes
for volatile matter content determinations.
[0121] The VCM in the coke from a delayed coker is primarily a
function of (1) feed properties, (2) drum pressure, (3) drum
residence time, (4) drum temperature, and (5) the level of steam
stripping in the decoking cycle. Though these parameters are noted
to affect the VCM content of the petroleum coke, the current
operating variables have no direct relationship with coke VCM. The
specific impacts of these parameters are very dependent on the
feedstock composition and coker design, and vary among refineries.
Based on years of experience, general rules of thumb regarding VCM
impacts have been developed and are provided below.
[0122] 1. With operating conditions held constant, a decrease in
feedstock gravity typically decreases the coke VCM. The properties
of the coker feedstocks play a major role in determining the
petroleum coke's VCM content. As noted above, the coke's volatile
combustible materials consist of certain cracked components, as
well as unreacted feedstock components in the coke drum.
Consequently, the coke VCM is dependent on the various
types/qualities of the organic compounds in the feedstock and the
relative quantities of these feedstock components.
[0123] 2. With other operating conditions held constant, a
reduction in coke drum pressure has been noted to decrease coke VCM
for a given feedstock. The coke drum pressure significantly affects
the coke VCM. A reduction in coke drum pressure increases the
vaporization of heavier cracked liquids or unreacted feedstocks.
Thus, the coke VCM is effectively decreased by the release of these
compounds that would otherwise remain with the coke. However, the
degree of coke VCM reduction is not easy to quantify and predict
for a specified level of pressure change.
[0124] 3. Reductions in cycle time have been noted to increase the
coke VCM. The drum residence time significantly affects the VCM in
the petroleum coke. As the coking cycle time decreases, the drum
fill rate increases, and the residence time for thermal cracking
and coking mechanisms decreases. Consequently, the reactions are
less complete, leaving more unreacted or partially reacted
feedstock on the coke as volatile combustible material.
[0125] 4. With other operating conditions held constant, an
increase in the drum vapor line temperature is noted to decrease
the coke VCM for a given feedstock. The drum temperature is a major
factor in determining the VCM in the petroleum coke. The local
temperatures in the drum determine the degrees of thermal cracking
and coking of the feedstock components. The temperature of the
vapors leaving the drum during the coking cycle (i.e. drum vapor
line temperature) is often used as the measured parameter to
represent the average coke drum temperature. This temperature is
typically 50-100.degree. F. lower than the heater outlet
temperature. The temperature difference is primarily due to a
combination of heat losses: (1) the endothermic reactions of the
thermal cracking and coking mechanisms, (2) vaporization energy of
the cracked components, and (3) drum heat loss. Since the asphaltic
coking mechanism is a physical change with no heat of reaction, the
drum vapor line temperature (e.g. 870.degree. F.) will likely
differ significantly for various feedstocks. That is, different
proportions of thermal coke and asphaltic coke mechanisms will
impact the drum vapor line temperature differently. For a given
feedstock, a higher drum vapor line temperature will cause greater
cracking reactions and/or vaporize heavier cracked components,
reducing the coke VCM. The drum vapor line temperature is normally
controlled by the heater outlet temperature and the amount of
condensed recycle.
[0126] 5. The steam-stripping step of the decoking cycle is noted
to decrease the coke VCM. The steam stripping during the decoking
cycle has less significant impact on the coke VCM. For example,
omitting the "big steam" step (the initial 0.5-1 hour of the
decoking cycle) will leave slightly more wax-tailing-type material
on the coke. Again, the coke VCM, under certain conditions, may
have weak chemical bonds to the coke that prevent steam
stripping.
[0127] E. Process Control of the Present Invention
[0128] The primary improvements of the present invention are
modifications to the operating conditions of the delayed coking
process, in a manner that is not suggested by prior art. In fact,
these changes in operating conditions are contradictory to the
teachings and current trends in the prior art. As noted previously,
the operating conditions of the prior art give first priority to
maximizing the efficiency of feedstock conversion to cracked liquid
products or maximizing coker throughput. In contrast, the operating
conditions of the present invention give first priority to increase
and consistently maintain the concentration of volatile combustible
material (VCM) in the resulting petroleum coke to 13-50 weight %
VCM (preferably 15-30% VCM). Second priority is given to
consistently provide a minimum-acceptable level of sponge coke in
the product coke. The third priority is THEN given to maximize
coker throughput and/or the conversion of coker feedstock blend to
cracked liquid products. In many cases, the reduction of cracked
liquids yield is expected to be <5% due to optimization of
embodiments of the present invention that reduce the overall VCM
increase and/or minimum sponge coke, required for acceptable
combustion. In some cases, implementation of the present invention
can actually increase overall cracked liquids production via
increased coke throughput capacity. The operating conditions
required to achieve the objectives of the present invention were
surprisingly modest, yet specific, relative changes from the prior
art.
[0129] As discussed previously, delayed coker operating conditions
vary greatly among refineries, due to various coker feedstocks,
coker designs, and other refinery operations. Therefore, specific
operating conditions (i.e. absolute values) for various refinery
applications are not completely possible for the present invention.
However, specific changes relative to existing operating conditions
provide specific methods of operational change to achieve the
desired objectives.
[0130] (1) Increased VCM in Delayed Coke:
[0131] Modifications in the delayed coker operating conditions are
necessary to achieve the production of a premium, "fuel-grade"
petroleum coke. These modifications increase and consistently
maintain the quantity and quality of VCM content in the petroleum
coke at a specified level. This new product specification for coke
VCM should be the minimum level that achieves a stable combustion
during various operating/load conditions for the end-user in its
particular combustion system. The VCM product specification is
expected to be in the target range of 13-50 weight percent
(preferably 15-30 wt. %). From the refiner's perspective, the
increase in VCM should be minimized and would preferably come from
feedstock and/or cracked components that are vaporized between
1000.degree. F. and 1742.degree. F. These components are less
valuable to the refiner and could conceivably include unreacted
feedstock and residual compounds after thermal cracking, as noted
above. From a combustion perspective, a certain amount of the VCM
increase should come from higher quality VCM components that
vaporize <1000.degree. F. (preferably <850.degree. F.) to
help initiate combustion of the coke. In fact, each combustion
system will likely have an optimal blend of volatile components
(i.e. >1000.degree. F. vs. <1000.degree. F.) that minimize
the overall VCM specification. Thus, the ideal modifications to
operational variables would achieve this optimal blend of volatile
components that minimize the overall VCM increase in the petroleum
coke, and provide narrow VCM target range for quality control.
[0132] As noted above, many operational variables indirectly affect
the coke VCM. As such, the selection of the appropriate
modifications in the delayed coker operating conditions is not
straightforward. In many cases, changes in the feedstock gravity
and reductions in coker cycle time tend to increase the coke VCM,
but provide limited change in VCM quality. Increases in drum
pressure tend to increase the quality and quantity of coke VCM, but
can be difficult to control coke VCM within a narrow target range.
The reduced steam stripping in the decoking cycle has been noted to
have limited effect on coke VCM content. However, reduced coke drum
temperatures tend to increase and maintain both the quality and
quantity of coke VCM. Reduced coke drum temperatures can decrease
the cracking reactions, increasing unreacted feedstock and
partially cracked components. In most cases, it provides a lower
vaporization temperature in the coke drum, leaving lighter cracked
or unreacted hydrocarbon components (i.e. higher quality VCM)
integrated in the coke. In addition, the coke VCM content can be
more predictable via reduced drum temperatures (vs. other
operational variables). As such, coke VCM content can be readily
controlled within a specified range. Furthermore, reduced coke drum
temperatures have the added benefit of improving the coke
crystalline structure (See below). Consequently, reduced coke drum
temperatures was selected as an exemplary means of increasing coke
VCM to achieve the objectives of the present invention.
[0133] Based on this analysis, a simple and exemplary means of
increasing and maintaining the volatile content of the coke (i.e.
to a consistent level between 13 and 50 wt. % VCM) would result
from a reduction of the average drum temperature by 5-80.degree. F.
(preferably 5-40.degree. F.). That is, a reduction in average coke
drum temperature from current operating conditions that produce
8-12 wt. % VCM for a given coker design and feed quality. In
general, an average drum vapor line temperature of 770 to
850.degree. F. can provide VCM levels of 15-30% for many cokers and
their respective feedstocks. However, as noted earlier, coker
feedstocks vary considerably among refineries, and can attain
15-30% VCM outside of this temperature range. In these situations,
the relative temperature drop from the existing average drum
temperature is expected to be similar. This lower drum temperature
would sufficiently reduce the cracking and coking reactions to
produce the desirable increase in VCM in the petroleum coke for
many existing refineries. While it is believed this result is
primarily due to (1) reductions in cracking reactions and (2)
increases in unreacted coker feedstock and partially cracked
liquids remaining with the resultant petroleum coke, the present
invention should not be bound by this.
[0134] The simplest means to achieve the lower average drum
temperature is to decrease the heater outlet temperature,
accordingly. That is, the heater outlet temperature is the primary
independent variable that can be controlled to achieve lower
average drum temperature. Changing the set point for the
temperature controller 22 can reduce the fuel rate, and lower the
heater outlet temperature to the desired level. However, as noted
above, there is no direct relationship between the heater outlet
temperature, the average drum temperature, and VCM in the resulting
petroleum coke. More specifically, the volatile content of the coke
significantly depends on the composition of the coker feed and the
relative impacts of the competing cracking and coking reactions on
its components. Thus, the VCM varies significantly due to the
different compositions in various coker feedstock blends.
Consequently, the optimal heater outlet temperature (to
consistently produce the desirable VCM content in the coke) is
expected to require the development of empirical data in pilot
plant studies for different coker designs and coker feedstocks.
Ideally, this new empirical data would not only address the impact
of various crude oil mixtures processed in the refinery, but also
evaluate the impact of other refinery operations. This type of
temperature control is analogous to other coker process
controls.
[0135] Regardless of the types of volatile components, the VCM
increase will usually create additional porosity of the residual
carbon in the combustion process. That is, the vaporization of
these components in the combustion process create greater voids
and, thus, more oxidation reaction sites in the residual carbon. In
addition, a VCM increase and the associated porosity increase are
also expected to further decrease the hardness of the coke. In many
cases, the softer petroleum coke can be ground to smaller particle
size distribution at the same or less energy in the current
pulverization equipment. Consequently, both greater porosity and
lower hardness provide better combustion characteristics, and
reduce the overall VCM specification required to achieve acceptable
combustion.
[0136] (2) Acceptable Delayed Coke Crystalline Structure:
[0137] Sponge coke is the most desirable crystalline structure for
fuel-grade petroleum coke. Needle coke is too dense for good
combustion properties. Shot coke is spherical in shape, and is
usually denser and harder than sponge coke. These characteristics
make shot coke difficult to grind to a desired particle size
distribution and more difficult to burn, particularly its carbon
residue. Sponge coke, on the other hand, has a high porosity that
increases with VCM. This high porosity makes sponge coke much
softer; easier to drill from the coke drum and easier than other
cokes (and most coals) to grind to the desired particle size
distribution for optimal combustion characteristics. The high
porosity of sponge coke (vs. most coals) also provides a greater
(or comparable) density of oxidation reaction sites in the carbon
residue after the initial combustion. This combustion
characteristic promotes better carbon burnout, which translates to
shorter residence time requirements, lower burnout temperature
requirements, and higher combustion efficiency.
[0138] Consequently, the second priority of the present invention's
process control is to consistently maintain levels of sponge coke
above a "minimum-acceptable" specification. As noted previously,
the sponge coke crystalline structure has higher porosity and lower
hardness (discussed below) than shot or needle coke. These
qualities are more conducive to good combustion characteristics.
Ideally, the entire coke product would be sponge coke crystalline
structure with higher VCM (e.g. 15-30 wt. %). This high-VCM sponge
coke has significantly greater porosity and lower hardness than
traditional sponge coke crystalline structure with lower VCM (e.g.
8-12% wt. %). However, with the high level of asphaltenes and
resins in modern, heavy coker feedstocks, this ideal may be
difficult to achieve. Even so, the ratio of asphaltic to thermal
coking mechanisms must be reduced sufficiently to consistently
provide at least the minimum acceptable level of sponge coke for
good combustion by the end-user. Since the degree of the asphaltic
coking mechanism is primarily a function of coker feedstock, an
increase in the thermal coking mechanism will likely achieve the
desired result.
[0139] In an exemplary embodiment, the decrease in heater outlet
temperature lowers the average drum temperature to increase coke
VCM (See above). This lower drum temperature favors the thermal
coking mechanism and promotes the formation of high porosity sponge
coke (versus shot coke). In this manner, the lower drum temperature
of an exemplary embodiment is expected to increase the degree of
thermal coking mechanism sufficiently to reduce shot coke to
acceptable levels. The new product specification for
"minimum-acceptable" sponge coke should be the minimum sponge coke
required to achieve a stable combustion during various
operating/load conditions for the end-user in its particular
combustion system. It should be noted that a low "acceptable"
sponge coke specification may be caused by or require a higher VCM
specification. Consequently, the sponge coke and VCM specifications
can be optimized for each application relative to the particular
refinery and coke end-user (as set forth herein). The
"minimum-acceptable" sponge coke product specification is expected
to be in the target range of 40-100 weight percent (preferably
60-100%), for combustion systems designed for bituminous coals.
[0140] Alternatively, a "maximum-acceptable" shot coke
specification or a specification for average coke density (gm/cc)
can provide other product quality measures for process control of a
particular coker design and feedstock. A "maximum-acceptable" shot
coke specification has the reverse logic of the above discussion.
Consequently, a new product specification for "maximum-acceptable"
shot coke should be the maximum shot coke that achieves a stable
combustion during various operating/load conditions for the
end-user in its particular combustion system. A
"maximum-acceptable" shot coke product specification is expected to
be in the target range of 0-60 weight percent (preferably 5-30%),
for combustion systems designed for bituminous coals. Similarly, a
product specification for average coke density could be developed
to provide coke quality control. That is, the desirable high VCM
sponge coke (e.g. 0.75-0.85 gm/cc) has a significantly different
density than shot coke (e.g. 0.9-1.0 gm/cc) or needle coke.
Consequently, the maximum average coke density specification would
likely reflect the composition of the upgraded petroleum coke for
the "minimum-acceptable" sponge coke or the "maximum-acceptable"
shot coke specifications.
[0141] F. Low-Level Decontamination of Coker Feedstocks; Desalting
Operations
[0142] As noted previously, the combustion of petroleum cokes
containing high concentrations of sulfur, sodium, and some heavy
metals (e.g. vanadium and nickel) has caused great apprehension due
to potential slagging and corrosion of the firebox and downstream
equipment. However, the effects of petroleum coke's high metals
content in combustion and heat transfer equipment is not well
understood or defined. The amount of slag formation on tubes (and
associated corrosion) depends on the ultimate composition of the
ash resulting from competing oxidation reactions. An analysis of
potential ash constituents from the combustion of these petroleum
cokes (See Table 1) indicates that compounds with melting points
<2500.degree. F. predominantly contain sodium (e.g. various
sodium sulfates and various sodium vanadates). Only four major
compounds without sodium are in this class: vanadium pentoxide,
nickel sulfate, aluminum sulfate, and ferric sulfate. However, the
lower oxides of these metals (i.e. V, Ni, Al, and Fe) can be
predominant (e.g. in a limited oxidation environment) and have
melting points in excess of 2850.degree. F. Also, ferric sulfate
and certain sodium sulfates decompose at a temperature near their
melting points. Based on this analysis, the primary element that
forms compounds with detrimental firebox effects is sodium. Thus,
as long as the sodium content of the coke remains low, the high
vanadium, nickel, and aluminum contents do not appear to create
significant ash fusion and associated corrosion. Even with higher
sodium levels in the crude, improvements in desalter operations can
provide the needed control.
[0143] Traditional desalting operations in oil refineries are
primarily designed to remove various water-soluble impurities and
suspended solids that are usually present in the crude oils from
contamination in the ground or in transportation. The prior art of
desalting focuses on the removal of salts in a manner that
substantially reduces corrosion, plugging, and catalyst poisoning
or fouling in downstream processing equipment. Most, if not all,
oil refineries have desalting operations. One to two stages of
desalting units in series are typically used to pretreat the crude
oils prior to the atmospheric crude oil distillation columns. A
third desalter stage can be added for vacuum distillation residuals
and other coker feedstocks, where undesirable components normally
concentrate. One stage is common, two stages are typical, but few
installations use three. The additional stages can increase
reliability and obtain additional reduction in the salt (and thus
sodium) content of the crude oil and downstream products. For
example, typical salt contents of crude oil range from 260-300
g/100m.sup.3 or roughly 40 pounds per thousand barrels (ptb) of
crude. The first stage can be designed and operated to reduce the
salt content by >90% to <4.0 ptb (significantly <15 ppm
sodium content). Two-stage desalter operations can be designed and
operated to reduce the salt content by >99% to <0.2 ptb
(significantly <5ppm sodium content). Finally, a third stage
desalter can be designed and operated to reduce the sodium content
of typical vacuum residuals to <1.5 ptb (or <5 ppm sodium).
This level typically translates to <25 ppm (or <0.05 lb./Ton)
of sodium in the petroleum coke. Consequently, current desalting
technology is capable of sufficiently reducing sodium in the
petroleum coke to levels that inhibit (and substantially reduce)
sodium compounds that cause ash problems in combustion systems.
Furthermore, the additional stages also provide incremental
reductions in other metals (Vanadium, Nickel, etc.) and
particulates that promote the precipitation of shot coke.
[0144] The present invention does not claim novel desalting
technology, but provides a novel application of such technology to
eliminate (or substantially reduce) potential ash problems
associated with the combustion of petroleum coke. Therefore,
further description of readily available desalting technologies was
not deemed appropriate, at this time. However, modifications to
existing, desalter operations may be required to achieve acceptable
sodium levels in the petroleum coke. That is, the actual
performance of the current desalter operation at specific
refineries depends on various design factors and operating
conditions. In the past, the increased investment cost for multiple
stages was usually justified by reducing the problems in downstream
processing equipment (corrosion, plugging, & catalyst poisoning
or fouling); not sodium levels for petroleum coke combustion.
Consequently, the installed desalting technologies may not be
currently designed and/or operated to accomplish this
objective.
[0145] An exemplary embodiment of the present invention uses three
desalting stages to pretreat the crude oil (stages 1 and 2) and
coker feedstock components (stage 3). The 3-stage desalting
system:
[0146] (1) minimizes or substantially reduces the concentration of
sodium in the resultant pet coke,
[0147] (2) promotes additional removal of other metals: Vanadium,
Nickel, Aluminum, etc., and/or
[0148] (3) provides greater reduction in particulates that promote
the precipitation of shot coke.
[0149] Trace quantities of acid, caustic, and other chemical or
biological additives can be injected into any or all stages to
promote removal of specific undesirable compounds. For example,
trace quantities of acid can be added to the water wash in the
first stage to promote additional removal of sodium, other alkali
and alkaline earth metals, and heavy metal compounds in the crude
oil. Trace quantities of caustic can be added to the water wash in
the second stage to promote additional removal of sulfur compounds
in the crude oil. However, sodium compounds, such as sodium
hydroxide, should not be used, and reintroduce higher levels of
sodium. Trace quantities of other chemical additives can be added
to the water wash in the third stage to promote removal of other
compounds of concern. However, since our primary goal is the
removal of sodium and other metals, trace quantities of acid in all
three stages can be desirable to maximize their reduction.
[0150] G. Impacts of the Present Invention on Refinery
Operations
[0151] The above embodiment of the present invention may cause
additional positive impacts on various refinery operations. First
of all, the reduced drum temperature (and associated decrease in
heater outlet temperature) can normally improve the delayed coker's
operation & maintenance and the quality of its cracked liquid
products. Secondly, any reduction of shot coke crystalline
structure can substantially reduce coker operational problems, as
well as improving combustion characteristics. Thirdly, the 3-stage
desalting operation improves the operation and maintenance of the
coker and other refinery operations. Finally, all of these
operational changes can also provide greater flexibility in
debottlenecking options for increasing the coker and/or refinery
throughput capacities. Most of these advantages lead to higher
coker throughput and/or lower operating and maintenance costs in
long-term.
[0152] The reduced average drum temperature of the exemplary
embodiment not only increases the coke VCM to the desired level,
but also provides other advantages in the coker operation. First,
the lower drum temperature favors thermal coke formation and
promotes higher porosity sponge coke. This upgraded petroleum coke
is substantially softer than the traditional petroleum coke due to
its higher VCM, higher porosity, and acceptable levels of shot
coke. Therefore, drilling of this softer petroleum coke in the
decoking cycle is less cumbersome, reducing decoking time and
associated maintenance. Secondly, a lower drum vapor line
temperature also reduces vapor limits without increasing drum
pressure and operating costs. In addition, the lower vapor
velocities from the coke drums normally decrease the entrainment of
coke fines to the fractionator in the coking cycle. Thirdly,
lowering the heater outlet temperature to achieve the lower drum
temperature can increase the drum fill rate, reducing drum limits
and coking cycle time. Finally, the reduced outlet temperature of
the coker heater reduces the severity of the delayed coker
operation, and consequently improves the coker operation and
maintenance. This coker operational change decreases the energy
consumption and cost for each barrel processed. The lower outlet
temperature also reduces the potential for coking in the heater,
onstream spalling, and its subsequent failure. Reducing these
factors usually increases heater run life, which is a primary
factor in coker run life. Also, the lower target outlet temperature
typically increases coker heater throughput capacity for a given
heater and feedstock. As such, the reduced outlet temperature
provides a greater opportunity for an increased drum fill rate,
reducing drum limits and coking cycle time. Reduction in both
coking and decoking cycles can lead to increased coker
throughput.
[0153] The reduced heater outlet temperature is also expected to
improve the quality of the cracked liquid products. The subsequent
thermal cracking is less severe and creates less olefinic
components in the gas oils. The olefinic components tend to be
unstable and form gum or sediments. As such, they are undesirable
in downstream processing (e.g. catalytic cracking). In addition,
the less severe cracking normally decreases the end point and
carbon residue of the heavy coker gas oil. The heavy residuum in
the coker heavy gas oil can create problems in downstream
processing equipment. For example, the heavy residuum in the feed
of fluid catalytic cracking units (FCCUs) often turns into coke on
catalyst, which can occupy the reaction sites of the catalyst,
decreasing catalyst activity and process conversion (or
efficiency). In addition, increasing the coke on catalyst normally
increases the severity of catalyst regeneration. In turn, severe
catalyst regeneration typically increases catalyst attrition,
particulate emissions, and catalyst make-up requirements.
Consequently, an exemplary embodiment of the present invention can
avoid these problems, improving downstream operations and product
quality.
[0154] Improved coke crystalline structure often reduces operation
and maintenance in delayed coker. Besides improving coke
grindability and combustion, reducing the production of shot coke
to acceptable levels improves coker operation and reduces safety
hazards. Shot coke contributes significantly to the following
problems: (1) Plugging the bottom coke nozzle; inhibiting proper
cooling steam, quench water, and drainage; increasing coking cycle,
(2) Channeling of quench water; creating coke drum hot zones and
dangerous conditions during cutting, and (3) Coke pouring out of
the drum; endangering cutting crew. Consequently, reductions in the
shot coke alleviate these operational problems. In addition, the
softer sponge coke with the higher VCM is less likely to produce
coke fines from the decoking operation. In turn, less coke fines
reduces erosion of the coke cutting nozzles.
[0155] The 3-stage desalting operation can improve the operation
and maintenance of the delayed coker and other refinery operations.
Sodium levels >15-30 ppm in the coker feedstocks are known to
accelerate heater coking. The efficient desalting normally (1)
inhibits coking in the heater, (2) decreases the need for onstream
spalling, and (3) increases coker heater run life. Efficient
removal of certain particulates also inhibits the formation of shot
coke. Most importantly, high efficiency desalting substantially
decreases corrosion in atmospheric and vacuum crude distillation
units and other downstream operations.
[0156] Finally, all of these operational changes can also provide
greater flexibility in coker and refinery deboftlenecking options.
As coker feedstocks change over time, coker throughput (and often
refinery throughput) is limited by the particular coker design.
Major design limitations are alleviated:
[0157] (1) Heater (or Temperature) Limited: Reduced heater outlet
temperature (as noted above) provides the opportunity to safely
increase heater capacity with reduced heater coking and online
spalling, while increasing heater (and potentially coker) run
life(s)
[0158] (2) Fractionator (or Vapors) Limited: Reduced severity in
thermal cracking will reduce the cracked vapors per barrel going to
the fractionator; potentially increasing coker capacity
[0159] (3) Coke Drum (or Coke Make) Limited: Increased drum fill
rate and decreased cutting time can be used to reduce coking and
decoking cycles to increase coker throughput
[0160] (4) Sour Crude Processing: High efficiency desalting reduces
corrosion in various refinery processes and increases the
refinery's tolerance of higher crude sulfur levels
[0161] (5) Heavy Crude Processing: Decreased cycle time can
increase coker throughput capacity, even with increased coke yield
(e.g. 2 hr .about.10-15%) and allow heavier crude residua
content
[0162] Since the coker is often the bottleneck in the crude
throughput of many refineries, debottlenecking the coker can also
translate into increased refinery throughput. In addition, factors
(4) and (5) provide greater flexibility in crude blends and the
ability to process inexpensive heavy, sour crudes. Thus, the
overall changes in coker operation are expected to include
optimization of various coking parameters, crude blends, and other
refinery operations, and maximization of coker and refinery
throughputs.
[0163] 2. Use of Premium "Fuel-Grade" Petroleum Coke: Conventional
Utility Boilers
[0164] An exemplary use of this new formulation of petroleum coke
is the replacement of most types of coals in conventional,
pulverized-coal (PC) boilers, utility, industrial, and otherwise.
As noted above, the upgraded petroleum coke of the present
invention has fuel characteristics that are superior to many coals,
which are currently used in conventional PC utility boilers. The
discussion of this exemplary embodiment includes (a) a basic
description of a conventional PC utility boiler system with.
traditional particulate control devices, (b) the combustion process
of the prior art, (c) the combustion process of the present
invention and its improvements, (d) the environmental controls of
the prior art, and (e) the environmental controls of the present
invention and their impacts. Finally, an example is provided, at
the end of this discussion, to illustrate the principles and
advantages of the exemplary embodiments of the present
invention.
[0165] When appropriate, comparisons are made to typical bituminous
coals, only for the sake of examples. Similar comparisons exist for
other coals, as well. The most important improvements in the use of
the upgraded petroleum coke are the abilities to maintain stable
combustion without auxiliary fuels and substantially reduce
environmental emissions. In particular, only modest modifications
are required to substantially reduce emissions of sulfur oxides,
while burning a fuel with significantly higher (or comparable)
sulfur content in the fuel.
[0166] A. Conventional, Pulverized-Coal (PC) Utility Boiler;
Process Description
[0167] As defined here, conventional, pulverized-coal utility
boilers include (but are not limited to) various coal combustion
systems used by power utilities to produce steam and subsequently
electricity via steam turbines. Typically, the coal combustion
system employs horizontally-fired coal burners that produce intense
flames in a high heat capacity furnace. A high heat capacity
furnace has tremendous capacity to absorb the intense heat released
by the combustion of the coal. The most common type of high heat
capacity furnace is lined with tubes filled with water, often
called a water-wall furnace. The horizontally-fired burners are
normally suspension burners, which convey fine, pulverized coal
particles via air (i.e. suspended by air) to the combustion zone.
Pulverized coal (PC) is usually provided to the burners by a
single, fuel processing/management system, which pulverizes,
classifies, and regulates the flow of the coal. Pulverization to
the desirable particle size distribution of coal particles is key
to achieving good combustion characteristics. Also, the coal
combustion system normally includes additional flue gas heat
exchange, sootblowing equipment, and various temperature controls
to optimize efficient use of energy.
[0168] In an exemplary embodiment of the present invention, a
conventional, pulverized-coal utility boiler with a traditional
particulate control device is modified to convert sulfur oxides to
dry particulates upstream of the existing particulate control
device(s). The prior art has been modified to achieve this
objective with Option 1: a retrofit addition of flue gas conversion
reaction chamber(s) and reagent injection system(s) and/or Option
2: dry reagent injection system(s) in the combustion system. FIG. 2
shows a basic process flow diagram for this modified system burning
a pulverized solid fuel as the primary fuel. Auxiliary fuel, such
as natural gas or oil, is used for start-up, low-load, and upset
operating conditions. The solid fuel 100 is introduced into the
fuel processing system 102, where it is pulverized and classified
to obtain the desired particle size distribution. A portion of
combustion air (primary air) 104 is used to suspend and convey the
solid-fuel particles to horizontally-fired burners 108. Most of the
combustion air (secondary air) 110 passes through an air preheater
112, where heat is transferred from the flue gas to the air. The
heated combustion air (up to 600 OF) is distributed to the burners
via an air plenum 114. The combustion air is mixed with the solid
fuel in a turbulent zone with sufficient temperature and residence
time to initiate and complete combustion in intense flames. The
intense flames transfer heat to water-filled tubes in the high heat
capacity furnace 116 primarily via radiant heat transfer. The
resulting flue gas passes through the convection section 118 of the
boiler, where heat is also transferred to water-filled tubes
primarily via convective heat transfer. At the entrance to the
convection section 118, certain dry reagents can be mixed with the
flue gas to convert undesirable flue gas components (e.g. sulfur
oxides) to dry particulates (i.e. exemplary embodiment: option 2).
The sorbents 120 pass through a reagent preparation system 122 and
are introduced into the flue gas via a reagent injection system
124. Steam or air 126 is normally injected through sootblowing
equipment 128 to keep convection tubes clean of ash deposits from
the fuel and formed in the combustion process. The flue gas then
passes through the air preheater 112, supplying heat to the
combustion air.
[0169] The cooled flue gas then proceeds to the air pollution
control section of the utility boiler system. At the exit of the
air preheater, certain dry reagents can be mixed with the flue gas
to convert undesirable flue gas components (e.g. sulfur oxides) to
dry particulates (exemplary embodiment: option 2). The reagents 130
pass through a reagent preparation system 132 and are introduced
into the flue gas via a reagent injection system 134. The existing
particulate control device 136 (ESP, baghouse, etc.) has been
retrofitted with the addition of a reaction chamber 138 (the
exemplary embodiment: option 1). Certain reagents (e.g. lime
slurry) can be prepared in a reagent preparation system 140. The
reagent is dispersed into the flue gas through a special injection
system 142. Sufficient mixing and residence time are provided in
the reaction chamber to convert most of the undesirable flue gas
components (e.g. sulfur oxides) to collectible particulates. These
particulates are then collected in the existing particulate control
device 136. A bypass damper 144 is installed in the original flue
gas duct to bypass (100% open) the retrofit, flue gas conversion
system, when necessary. The clean flue gas then exits the stack
148.
[0170] B. Combustion Process of the Prior Art
[0171] The conventional, PC-fired utility boiler system, described
above, can successfully burn a wide variety of solid fuels. Various
types of coal are burned in such systems throughout the United
States and internationally. Bituminous, sub-bituminous, and lignite
coals are commonly used in this type of combustion system. Low
volatile, solid fuels (such as traditional petroleum coke,
anthracite coals, and low-volatile bituminous coals) typically
cannot be used as the primary fuel in these types of boilers. These
solid fuels often require non-conventional types of combustion
systems, including cyclone furnaces, fluidized bed combustors, or
down-fired burners into a low heat capacity furnace (e.g.
refractory lined). The design of each conventional, PC-fired
combustion system, though, varies greatly and depends on (1) each
coal's respective fuel properties and combustion characteristics,
and (2) the quantity and quality of steam required.
[0172] The integrated design of a conventional, PC-fired utility
boiler and associated systems is a complex engineering effort.
Various design and operational factors must be given proper
consideration. These design and operational factors include (but
are not limited to) the following:
[0173] Fuel Properties: VCM, ash content, moisture content, char
quality, particle size distribution (PSD), carbon/hydrogen ratio,
oxygen content, adiabatic flame temperature, burning profiles,
etc.
[0174] Combustion Characteristics: flame stability, flame
temperature, flame turbulence, flame residence time, excess air,
air preheat (primary & secondary air), carbon burnout,
combustion efficiency, etc.
[0175] Burner Design: size, number, flame shape, fuel/air mixing,
pressure drop, low emissions, etc.
[0176] Furnace Design: size, shape, refractory & heat transfer
properties, tube layout & metallurgy, etc.
[0177] Steam System Design: water & steam quality, tube number
& spacings, sootblowing, etc.
[0178] Fuel Preparation System: pulverizer capacity &
energy/grinding characteristics, in/out PSDs, etc.
[0179] Engineers skilled in the art typically use complex computer
models to optimize the integrated design, based on substantial
combustion experience and various design factors (including those
noted above). Therefore, the remaining discussion about the
combustion prior art will be limited to fuel property
considerations that significantly affect the fuel decisions for new
boilers and fuel switching in existing boilers. Though this
discussion is primarily focused on various coals to simplify
explanation, the principles involved apply to other solid fuels as
well.
[0180] Numerous references discuss the combustion science related
to burning solid fuels. Many provide theories of combustion and the
relative impacts of various fuel properties, including ash content,
moisture content, char quality, and particle size. These issues are
discussed in the present invention, where it is relevant. However,
two other fuel properties, that are not universally discussed, are
key to accurately describe the present invention. Both fuel
properties, grindability indexes and burning profiles, are
important factors in the evaluation of potential fuel substitutions
in conventional, PC-fired combustion systems.
[0181] (1) Grindability Index:
[0182] A fine particle size distribution of coal from the
pulverizer is a critical parameter in achieving good combustion
efficiency. That is, for a given coal, smaller coal particles
normally require less residence time and/or lower temperatures to
provide good char burnout and less unburned carbon. The ability to
pulverize the coal to finer particle size distributions is related
to the coal's hardness. However, a grindability index provides a
more comprehensive comparison of the overall grindability of
various coals.
[0183] Babcock & Wilcox developed one type of grindability
index test, called the Hardgrove Grindability Index (HGI). This
laboratory procedure, ASTM Method D 409, is an empirical measure of
the relative ease with which coal can be pulverized. The HGI has
been used for the past 30 years to evaluate the grindability of
coals. The method involves grinding 50 grams of air-dried test coal
(16.times.30 mesh or 1.18 mm.times.600 um) in a small ball-and-race
mill. The mill is operated for 60 revolutions and the quantity of
material that passes through a 200 mesh (75 micron) screen is
measured. From a calibration curve relating -200 mesh (-75 micron)
material to the grindability of standard samples supplied by the
U.S. Department of Energy, the Hardgrove Grindability Index (HGI)
is determined for the test coal. The higher the HGI, the more
easily the coal can be pulverized to fine particle size
distributions. Pulverizer manufacturers have developed correlations
relating HGI to pulverizer capacity at desired levels of
fineness.
[0184] (2) Burning Profiles:
[0185] As noted above, many fuel properties need proper
consideration in the integrated design of a solid-fuel combustion
system. One of the most comprehensive evaluations of the overall
combustibility of a solid fuel is the burning profile. One type of
burning profile test was developed by Babcock & Wilcox. This
laboratory procedure measures the entire course of combustion for a
tested fuel, from ignition to completion of burning.
[0186] The B&W procedure, described by Wagoner and Duzy, uses
derivative thermogravimetry, in which a fuel is oxidized under
controlled conditions. A 300 mg sample with a particle size less
than 60 mesh (250 microns) is heated at a fixed rate (27.degree. F.
per minute: 68 to 2012.degree. F.) in a stream of air. Weight
change (mg/min) is measured continuously. The graphical
presentation of these data (mg/min vs. temperature) provides a more
complete picture of the entire combustion process, through
examination of the solid fuel's oxidation rates. For example, FIG.
3 shows the burning profiles representing each classification of
coal. The height of each oxidation peak is proportional to the
intensity of the oxidation reactions and flame. The area under each
peak is noted to be approximately proportional to the amount of
combustible material in the sample and/or the total heat liberated.
In general, bituminous, sub-bituminous, and lignite coals have
greater oxidation rates at lower temperatures than anthracite
coals. This indicates easier ignition and burning. Such fuels would
be expected to burn more completely in the lower part of the
furnace. Profiles that extend into very high temperature ranges,
such as anthracite coal, indicate slow burning fuels for which
longer residence times in high temperature zones are necessary for
efficient combustion. Thus, the maximum temperature on the burning
profile helps determine the requirement for furnace residence time
at high temperature to obtain a low unburned carbon loss, and thus
higher combustion efficiency.
[0187] Burning profiles are very repeatable for the same operating
conditions and test furnace. However, the same solid fuel will show
a different burning profile for changes in heat transfer rates,
sample size, particle size distribution, air flow rate, etc.
Consequently, the burning profiles provide a good qualitative
comparison of relative burning properties for solid fuels, but can
be limited to combustion with identical or very similar
conditions.
[0188] A major shortcoming of the B&W burning profile test
procedure is the preparation of the various fuel samples at a
specified particle size distribution. The fuel sample is ground to
less than No. 60 Sieve (.about.250 microns) and care is specified
to produce a minimum of fines. In contrast, various coals are
pulverized to 60-90% through 200 Sieve (.about.74 microns) for
various combustion applications. As discussed previously, the
particle size distribution has a substantial impact on a solid
fuel's oxidation rate. Consequently, a modified test procedure is
desirable to reflect relative differences in HGI and the
grindability characteristics for various fuels. For example, the
burning profile test procedure can be modified to prepare fuel
samples with a constant grinding energy, yet minimize the
generation of fines. For testing purposes, the fuel samples would
still have a particle size distribution that is much larger than
the commercial facility. In this manner, the relative combustion
impacts of fuel grindability and resultant particle size
distribution can be incorporated into the burning profile.
[0189] (3) Fuel Substitution:
[0190] Burning profiles can be effectively used to evaluate the
potential substitution of one solid fuel for another. Coals with
similar burning profiles have been noted to behave similarly in
large furnaces of equivalent design and operation. Thus, comparison
of the burning profile of an unknown solid fuel to that of a solid
fuel that has proven performance can provide useful information to
predict design (e.g. furnace & burners) and operating
conditions (e.g. excess air and burner settings). Furthermore,
comparison of the burning profiles for an alternative solid fuel
and a solid fuel with proven performance in a particular furnace
design can provide a preliminary evaluation of the ability to
substitute one fuel for another in a particular combustion
system.
[0191] Similar burning profiles provide a higher degree of
confidence in the ability to substitute one solid fuel for another.
However, a perfect match of burning profiles is not necessary, and
can be undesirable. For example, the first peak in the burning
profile of coals with high moisture is the evaporation of the
coal's water content. Providing a substitute solid fuel with this
burning profile characteristic can be undesirable due to the
detrimental combustion effects of moisture. Also, very volatile
fuels may be undesirable due to concerns of premature ignition and
excessive flame intensity. Furthermore, a low temperature peak from
low-quality volatiles (e.g. carbon monoxide) can be less desirable
due to its effects that cause lower heating value and higher fuel
usage. Consequently, the comparison of burning profiles is a
preliminary evaluation, which requires further optimization of
basic fuel properties and combustion characteristics.
[0192] Optimal ignition and char burnout are key properties in
achieving a successful solid fuel switch. Optimal ignition
characteristics would provide self-combustion in a conventional PC
boiler without auxiliary fuel, while avoiding premature ignition,
excessive flame intensity, or lower heating value. Optimal char
burnout would provide high combustion efficiencies (i.e.
insignificant unburned carbon) at sufficiently low temperatures and
residence times to complete combustion in the lower furnace, while
avoiding excessive flame intensity.
[0193] Finally, derating the boiler's capacity and reducing
efficiency are major concerns of fuel switching. As such, switching
an existing solid fuel to a higher quality fuel is often preferable
to switching to a lower quality fuel. For example, most of the
western U.S. low sulfur coals are sub-bituminous rank that have
higher moisture, comparable ash, and lower quality volatiles than
bituminous coals being replaced. Consequently, their lower heating
values (and capacity derating effect) limit their application to
partial substitution or boilers with low load factors. However, in
certain situations, the reduction in sulfur oxides emissions is
more important than the ability to maintain high load factors.
[0194] C. Combustion Process of the Present Invention
[0195] The new formulation of petroleum coke of the present
invention has an unexpected ability to burn successfully, even with
relatively low VCM content. The combustion of this upgraded coke is
compared to traditional delayed coke and most coals. Its superior
fuel properties and combustion characteristics are discussed,
including ash/moisture effects, char quality (particle size,
porosity, etc.), ignition/residence time issues, and burning
profiles. Finally, superior characteristics of the upgraded
petroleum coke are then discussed for each of the following
subsystems of the conventional PC utility boiler: fuel processing,
combustion, and heat transfer.
[0196] (1) Combustion Quality of Traditional Petroleum Coke:
[0197] A burning profile representing a traditional petroleum coke
was added to FIG. 3 for comparison to burning profiles of various
types of coal. In general, this traditional petroleum coke has a
burner profile similar to low-volatile, bituminous coal. Other
traditional petroleum cokes (e.g. shot and Fluid coke) have burner
profiles more similar to anthracite coals. In either case, the
similar burner profiles show why traditional petroleum cokes
require low heat capacity furnaces commonly used for these coals
(e.g. cyclone furnaces). As such, traditional petroleum coke can
only be considered for direct fuel substitution in special furnaces
capable of firing these hard-to-burn coals.
[0198] Further analysis of this traditional petroleum coke's
burning profile demonstrates even poorer combustion characteristics
than these "similar" coals. First, the initial ignition temperature
(.about.600-650.degree. F.) is comparable to low-volatile
bituminous and high-volatile anthracite coals, but significantly
higher than high volatile bituminous, subbituminous, and lignite
coals. This higher initial temperature of weight loss in the
burning profile is caused by the low-quality, volatile content of
the traditional petroleum coke. Secondly, the maximum rate of
weight loss (oxidation peak) for this traditional petroleum coke is
.about.10-20% lower than most coals. This lower oxidation peak can
be attributed to the coke's lower quality/quantity of VCM (11.7 wt.
% VCM) and poor char quality (e.g. shot coke). That is, the coke's
devolatilization and char burnout are not as rapid, creating lower
oxidation intensity. Thirdly, the area under the curve is
significantly smaller than the coal's, indicating the total sample
did not oxidize. With complete combustion, the traditional
petroleum coke would be expected to have a larger area under the
curve, representing relatively greater proportion of combustible
material due to its much higher heating value and lower
ash/moisture contents. This unburned carbon can be caused by
several factors, including the coke's lower quality/quantity of VCM
and poor char quality. Finally, the completion of combustion occurs
at approximately 1550-1600.degree. F. This undesirable, combustion
completion temperature is again comparable to low-volatile
bituminous and high-volatile anthracite. Profiles that extend into
these high temperature ranges indicate slow-burning fuels, which
require longer residence times in high temperature zones for
efficient combustion.
[0199] In conclusion, this burning profile analysis indicates the
production of a petroleum coke that sustains self-combustion may
require more than simply an increase in coke VCM. Substantial coke
combustion experience of the inventor further supports this
conclusion. Various coke/oil slurries that simply add VCM external
to the coking process have been attempted with limited success. The
oil provides a high quantity of high-quality VCM. However, this
method does not change the poor char quality. Similarly, a higher
quantity of low quality VCM is normally not sufficient to initiate
and sustain self-combustion without a substantial change in the
coke's char quality.
[0200] (2) Combustion of Upgraded Versus Traditional Petroleum
Coke:
[0201] The new formulation of petroleum coke in the present
invention has substantially better fuel properties and combustion
characteristics than the traditional "fuel-grade" petroleum coke.
The primary difference is the ability to initiate and sustain
self-combustion in a conventional, high heat capacity furnace
without the use of auxiliary fuels, except for start-up. For
example, the upgraded coke, unlike traditional coke, can be
effectively burned in a conventional, pulverized-coal boiler. The
superior combustion characteristics result from 3 primary changes
in the new formulation of the exemplary embodiment:
[0202] (1) Increased quantity and quality of VCM: improves ignition
and char burnout,
[0203] (2) Improved char quality of the modified sponge coke:
higher porosity and reactivity, and
[0204] (3) Softer coke: ability to pulverize to a smaller particle
size with same or less energy input.
[0205] The combined effect is expected to have the following impact
on the petroleum coke's burning profile: (1) move the burning
profile curve to the left (i.e. lower ignition and combustion
completion temperatures), (2) increase maximum rate of weight loss
(or peak flame intensity), and (3) increase the area under the
curve (increase proportion of combustible material oxidized). These
factors improve the ignition, char burnout characteristics, flame
quality, and combustion efficiency.
[0206] Further embodiments of this invention provide additional
means to increase the quality and quantity of the volatile
combustible materials in the upgraded petroleum coke. These other
embodiments provide options to improve further the combustion
characteristics of the upgraded petroleum coke. With these
additional embodiments, the upgraded petroleum coke is expected to
initiate and complete combustion at lower temperatures and require
lower combustion residence times. Consequently, the burning
profiles of the upgraded coke are expected to move further to the
left.
[0207] (3) Combustion of Upgraded Petroleum Coke Versus Most
Coals:
[0208] The fuel properties and combustion characteristics of
petroleum coke are improved sufficiently by the present invention
to replace most coal fuels (e.g. in conventional, PC utility
boilers). An exemplary embodiment of the present invention is
expected to improve petroleum coke sufficiently to directly replace
many high volatile bituminous, subbituminous, and lignite coals. In
cases where direct replacement is not possible, the improved
qualities are sufficient to replace these coals with modest to
moderate modifications in the design and/or operation of the
combustion system (i.e. burners, furnace, etc.).
[0209] a. Superior Fuel Properties:
[0210] The premium, "fuel-grade" petroleum coke typically has
better combustion characteristics than most coals due to more
desirable fuel properties The primary coke fuel properties
affecting combustion characteristics include the following: lower
ash, lower moisture content, lower grindability hardness, greater
fuel consistency, and significantly higher (or comparable) porosity
of the residual carbon. Tables 2-A and 2-B provide comparison of
key differences in fuel properties, combustion characteristics, and
environmental performance for traditional petroleum cokes, upgraded
petroleum cokes of the present invention (i.e. OptiFuel ) and many
examples of various types of coal. Compared to most coals, the
upgraded petroleum coke typically has 90+% lower ash content,
75-90+% lower moisture content, and 10-250+% higher heating values.
The fuel rate is typically decreased by 10-40+%. The significantly
lower fuel rate can decrease the total quantity of undesirable
components (e.g. sulfur), even with higher component contents (wt.
% in pet coke vs. coal). Sulfur, nitrogen, and carbon contents of
the upgraded coke are normally comparable or higher. The VCM
content is typically lower for comparable combustion
characteristics (e.g. burning profile) and fuel use
applications.
[0211] b. Improved Combustion Characteristics:
[0212] The superior fuel properties of the upgraded petroleum coke
from the present invention provide improved (or comparable)
combustion characteristics relative to most coals. More desirable
combustion characteristics are expected to include (but are not
limited to) (1) superior ash and moisture combustion effects, (2)
increased residence time, (3) better (or comparable) char quality
& burnout, and (4) improved combustion stability with lower
excess air rates.
[0213] 1. Superior Ash and Moisture Combustion Effects: The lower
ash and moisture contents of the upgraded petroleum coke affect a
variety of combustion characteristics. Ash and moisture absorb heat
in the combustion process. This increases the required ignition
temperature and reduces the flame temperature (adiabatic and
actual). Also, high ash and moisture contents substantially reduce
the heat content (Btu/pound) of the fuel and require more pounds of
fuel for a given heat release rate in the combustion system.
Consequently, lower ash and moisture contents of the upgraded
petroleum coke increases flame temperature and heating value and
reduces required ignition temperature and fuel rates.
[0214] 2. Increased Residence Time: The lower fuel rates and
associated reduction in air rates normally increase operating
capacities in an existing boiler for the pulverizer, fan, and
boiler systems. In addition, the lower fuel and air rates can
significantly increase the residence time in the existing boiler
system, usually improving combustion efficiency (e.g.
carbon-burnout), boiler efficiency (e.g. better heat transfer), and
environmental control efficiency (e.g. reduced ESP velocity: Q/A).
In most cases, upgraded coke also decreases flue gas flow, system
pressure-drop, and associated auxiliary power.
[0215] 3. Better Char Quality and Burnout: The high porosity,
sponge coke of the present invention provides better char quality
that favors superior carbon burnout to most coals. The higher
porosity provides more accessible combustion reaction sites, and
promotes more complete carbon burnout. As discussed below, the
significantly lower hardness (HGI=80-120+) allows more flexibility
in grinding the coke to a much finer particle size distribution at
lower grinding energies. The finer particle size of the fuel
promotes more efficient and complete combustion, particularly for a
low VCM fuel.
[0216] 4. Improved Combustion Stability with Lower Excess Air: The
upgraded petroleum coke is produced by a chemical process that
provides less variability in composition and combustion
characteristics than coal(s) from different veins in the same mine
or even different mines.
[0217] That is, the upgraded petroleum coke of the present
invention has more uniform fuel properties and combustion
characteristics. This fuel consistency normally improves flame
stability and decreases excess air requirements for similar load
variations.
[0218] 5. Catalytic Oxidation Effects: The metals content of
petroleum coke (upgraded or traditional) often contains higher
levels of heavy metals, such as vanadium and nickel. These metals
can provide a positive benefit as an oxidation catalyst to improve
combustion characteristics and efficiency.
[0219] All these factors give the upgraded petroleum coke firing
capabilities and combustion characteristics that are superior (or
comparable) to coals with significantly higher VCM content. High
quality VCM, high porosity sponge coke, and finer particle size
distribution of the upgraded coke fuel are primary features of the
present invention that reduce the overall VCM requirement relative
to various coals. Low ash and moisture content are also
contributing factors. In conclusion, the fuel qualities of the
upgraded petroleum coke are expected to promote (1) a more uniform
and stable flame, (2) acceptable combustion at lower excess air
operation, and (3) better char burn-out characteristics than most
coals, over a wide range of operating conditions.
[0220] As noted above, additional embodiments of this invention
provide additional options to increase the quality and quantity of
the volatile combustible materials in the upgraded petroleum coke.
That is, high quality VCM (e.g. BP Range: 350-750.degree. F. &
heating value: 16-20,000+btu/lb) can be integrated into the
petroleum coke crystalline structure. In this manner, the burning
profile of the upgraded coke can be adjusted to optimize desirable
combustion characteristics for replacing solid fuels in a
particular combustion system (See: Optimal Fuel Embodiment). This
can be accomplished by matching the burning profile of the existing
solid fuel or achieving other desirable burning profile
characteristics. For example, production of an upgraded petroleum
coke with optimal ignition and char burnout characteristics can
also be achieved. Again, in cases where direct replacement is not
possible, the improved qualities are sufficient to replace these
coals with modest to moderate modifications in the design and/or
operation of the combustion system (i.e. burners, furnace,
etc.).
[0221] (4) Combustion of Upgraded Petroleum Coke vs. Low Sulfur
Coals:
[0222] Most low-sulfur coals referred to in this section are
actually a subset of the previous section (i.e. most coals).
Consequently, the comparison of fuel properties and combustion
characteristics are still valid in this section. However,
low-sulfur subbituminous coals are a special subset of "Most Coals"
that warrants further discussion, due to their current use as fuel
alternatives to comply with U.S. environmental laws.
[0223] Many PC utility boilers in the United States are being
switched from bituminous coal to subbituminous, low-sulfur coal to
comply with EPA regulations caused by the CAAA of 1990. The
subbituminous, low sulfur coal typically has comparable ash
contents, higher moisture contents and lower heating values (vs.
bituminous coal). The fuel rate is typically increased by 20-40+%.
The substantially higher fuel rate usually increases the ash
quantity, even with lower ash content (wt. %). Consequently, a fuel
switch to this low-sulfur coal normally requires boiler derating
(operating with lower capacity), pulverizer derating, and
mitigating problems with particulate emissions. Other problems
often include increases in air requirements, flue gas flow, system
pressure-drop, and associated auxiliary power. Most of these
factors lead to decreased combustion, boiler, and environmental
control efficiencies.
[0224] In contrast, a fuel switch to the upgraded petroleum coke of
the present invention will have the opposite impact on most of
these factors. Table 2-A shows that the upgraded petroleum coke
(vs. bituminous coal) typically has 95+% lower ash content, 5-30+%
lower moisture content, and 10-25%% higher heating values. The fuel
rate is typically decreased by 10-20+%. The significantly lower
fuel rate usually decreases the overall sulfur quantity, even with
higher sulfur content (wt. %). Consequently, a fuel switch to the
upgraded coke increases operating capacities for the pulverizer,
fans, boiler, and environmental control systems. Decreases in air
requirements, flue gas flow, system pressure-drop, and associated
auxiliary power can often lead to increased combustion, boiler, and
environmental control efficiencies, as well. In conclusion, fuel
switching from most coals (including low sulfur, subbituminous
coals) to the upgraded petroleum coke of the present invention can
significantly improve the various subsystems of the conventional,
PC utility boiler: fuel processing, combustion and heat
transfer.
[0225] (5) Fuel Processing Improvements:
[0226] The higher VCM, lower ash content, and lower hardness of the
upgraded petroleum coke greatly reduce the fuels handling
challenges and equipment wear. First, the upgraded petroleum coke
has the capability of being the only fuel required, allowing the
use of one fuel processing and management system, existing or
otherwise. In contrast, the prior art for combustion of
traditional, fuel-grade petroleum coke in a utility boiler requires
a coke/coal blend, which often required separate fuel processing
systems for the coal and petroleum coke, respectively. Secondly,
the upgraded petroleum coke has dramatically lower ash content
(0.1-1.0 wt. %) and moisture content (.5-4.0 wt. %) than most coals
(Ash=5-70 wt. % & Moisture=5 to >50 wt. %). The lower ash
and moisture contents give the upgraded petroleum coke a
substantially higher heating value: (13.0-15.5 MBtu/lb) than most
coals (10.5-13.0 MBtu/lb). Consequently, the conventional utility
boiler requires substantially less tons of the upgraded petroleum
coke for a given heat release rate. Thirdly, the upgraded coke of
this invention also is dramatically softer than most bituminous
coals, as indicated by its lower HGI of 80-120+, compared to
20-80+of typical bituminous coals and <60 for traditional
petroleum cokes. Consequently, the existing pulverization equipment
can normally grind the upgraded coke to a much finer particle size
distribution, at the same level of grinding energy. For example,
60-80% through 200 mesh is typical for various ranks of coals
(lignite to anthracite). The upgraded petroleum coke can usually
achieve 85-95+% through 200 mesh with less (or comparable) grinding
energy. This very fine particle size distribution further improves
its combustion characteristics. Alternatively, the upgraded coke
could be ground to the same particle size distribution (or any
point in between) with a lower grinding energy and cost. Both the
reduced fuel rate (e.g. Tons/hour) and the lower hardness (softer
material) are expected to substantially reduce erosion, equipment
wear, and operating & maintenance costs in the fuel processing
and combustion systems.
[0227] (6) Combustion Improvements:
[0228] As discussed previously, the upgraded petroleum coke
provides superior fuel properties and improved combustion
characteristics relative to traditional petroleum coke and most
coals. The fuel properties of the upgraded coke are superior to
traditional coke due to (1) increased quantity and quality of VCM
(improves ignition and char burnout), (2) improved char quality of
the modified sponge coke (higher porosity and reactivity), and (3)
softer coke (ability to pulverize to a smaller particle size). The
fuel properties of the upgraded coke also provide improved
combustion characteristics relative to most coals: (1) superior ash
and moisture combustion effects, (2) increased residence time, (3)
better char quality and burnout, (4) improved combustion stability
with lower excess air, and (5) catalytic oxidation effects.
[0229] (7) Heat Exchange Improvements:
[0230] In most cases, the premium, fuel-grade petroleum coke is
expected to have better heat transfer characteristics and overall
thermal efficiency. In operating conditions with more uniform and
stable flames, the upgraded petroleum coke is expected to provide
better radiant heat transfer characteristics. The much lower ash
also dramatically reduces the fouling of heat transfer surfaces and
the need for sootblowing of convective heat exchange surfaces. The
better heat transfer characteristics, reduced fouling, combustion
with lower excess air, and better (or comparable) carbon burnout
provide greater thermal efficiency for a combustion system fired
with the upgraded petroleum coke. Low ash fusion temperatures are
not expected to create heat exchange problems due to the low-level
decontamination to remove sodium and vanadium from the petroleum
coke to acceptable levels.
[0231] D. Environmental Controls of the Prior Art
[0232] Various technologies currently exist for particulate control
and removal of undesirable pollutants, primarily sulfur oxides SOx.
The present invention does not claim these technologies separately,
but provides improvements and novel combinations of these
technologies in applications of the present invention, particularly
in retrofit applications.
[0233] (1) Particulate Control Device (PCD) Fundamentals:
[0234] Particulate emissions from solid-fuel combustion come from
noncombustible, ash forming mineral matter in the fuel. Additional
particulates are unburned carbon residues from incomplete
combustion of the fuel. Though solid particulates from solid-fuel
combustion primarily range in size from 1-100 microns, finer
particulates less than 10 microns are the focus of recent
environmental concerns. "Bottom ash" refers to larger, heavier
particulates that are collected in hoppers beneath the furnace of
the combustion facility. "Flyash" refers to finer ash that is
entrained in the flue gas and is collected in heat exchange/air
preheater hoppers and various types of particulate control
equipment. Traditional particulate control devices (PCDs) for
conventional, solid-fuel combustion systems include (but are not
limited to) electrostatic precipitators (ESPs), various types of
filtering systems, mechanical collectors, and wet scrubber
systems.
[0235] a. Electrostatic Precipitators (ESP):
[0236] A wide variety of ESP technologies has evolved through the
years, including dry and wet versions. The electrostatic
precipitator electrically charges the particulates in the flue gas
to collect and remove them. The ESP is comprised of a series of
parallel vertical plates through which the flue gas passes.
Centered between the plates are charging electrodes which provide
the electric field. The negatively charged particles are attracted
toward the grounded (positive) collection plates and migrate across
the gas flow. The charging electrodes and collection plates are
periodically cleaned by rapping these components and dislodging
sheets of agglomerated particles that fall into large hoppers. ESPs
have low pressure drops due to their simple design characteristics.
ESP collection efficiencies can be expected to be 95-99+% of the
inlet dust loading. Overall ESP performance depends on various
design and operational factors, including (but not limited to)
flyash loading, particle resistivity, particle drift velocity,
electric field strength, and the ratio of plate surface area to
flue gas flow. Lower sulfur concentrations in the flue gas can lead
to lower ESP collection efficiency due to their effects on particle
resistivity. ESPs are available in a broad range of sizes for
utility and industrial applications.
[0237] b. Fabric Filters:
[0238] Various types of filtering systems have evolved as well. The
more popular types include numerous tubular (or bag) filters in
parallel flow arrangements, and have been commonly referred to as
baghouses. Baghouse systems usually have multiple compartments with
each compartment containing hundreds to thousands of bag filters.
The baghouse, or fabric filter, collects the dry particulates as
the cooled flue gas passes through the porous filter material that
separates the particulate from the flue gas. Agglomerated layers of
particulates (commonly called filtercake) accumulate on the filter
material. This filtercake increasingly restricts the gas flow,
until the filter media is cleaned. Different baghouse technologies
have a variety of designs to continually clean the filtering media
in temporarily inactive compartments: pulse jet, reverse air,
shaker and deflation. Fabric filters have significantly higher
pressure drops than ESPs due to the filter media and filtercake.
However, power usage of fabric filters and ESPs tend to be similar
because the additional fan power needed to overcome the increased
pressure drop in fabric filters is approximately equal to the power
consumed in the ESP transformer rectifier sets. Fabric filter
collection efficiency can be expected to be 95-99+%. Fabric filters
are substantially more effective than ESPs in the removal of
particulates less than 2 microns. Overall performance depends on
various design and operational factors, including (but not limited
to) flyash loading, gas-to-cloth ratio, pressure drop control, and
type/porosity of filter material. Fabric filters are considered to
be more sensitive to operational upsets or various load swings than
ESPs due to maximum temperature and stress limitations of the
filter material. Finally, fabric filters have the potential for
enhancing SOx capture in installations downstream of SOx dry
scrubbing or dry sorbent injection systems (via longer reagent
exposure & reaction residence times in the filter cake).
[0239] c. Mechanical Collectors:
[0240] Mechanical dust collectors, often called cyclones or
multiclones, have been used extensively to remove large particles
from a flue gas stream. The cyclonic flow of gas within the
collector and the centrifugal force on the particles drive the
larger particles out of the flue gas. Cyclones are low cost,
simple, compact and rugged devices. However, conventional cyclones
are limited to collection efficiencies of about 90% and are poor at
collecting the smallest particulates (<10 microns). Improvements
in small particulate collection require substantially higher
pressure drops and associated costs. Consequently, mechanical
collectors had been widely used on small combustion facilities when
less stringent particulate emission limits applied.
[0241] d. Wet Scrubbers:
[0242] Finally, various wet scrubber systems have evolved to
control particulate and other emissions, including sulfur oxides.
Wet scrubbing technologies for combined particulate and SOx control
typically employ high pressure drop, turbulent mixing devices (e.g.
venturi scrubbers) with downstream separation. However, the high
energy consumption of this type of wet scrubber made them
impractical for use with larger combustion facilities, particularly
modern, utility boilers. Pressure drops of 10-72 inches of water
are necessary for >85% removal of particulates down to 0.5-1.0
microns. In contrast, only 0.5-1.5 inches of water are required to
achieve >85% collection of particles >10 microns in gravity
spray towers. These low pressure-drop, wet scrubbers can achieve
some ash particulate control, but are primarily used for the
control of sulfur oxides. Particulate sulfur compounds formed in
this process are collected in liquid film or droplets.
[0243] (2) Sulfur Oxides (SOx) Control Fundamentals:
[0244] A variety of SOx control technologies are in use and others
are in various stages of development. Commercialized flue gas
desulfurization (FGD) processes for solid-fuel, combustion
facilities include (but are not limited to) wet, semi-dry (spray
dry adsorption), and completely dry (dry sorbent injection)
systems. In all three of these system types, alkaline reagent(s)
(i.e. compounds of alkali or alkaline earth metals) reacts with the
sulfur oxides to form collectible sulfur compounds. Wet scrubber
systems normally have upstream particulate control devices (PCDs)
to remove any flyash prior to SOx removal, and collects its sulfur
products in a liquid film. In contrast, sulfur products from the
spray dry adsorption and dry sorbent injection systems are usually
collected together with the flyash in downstream PCDs.
[0245] a. Wet Scrubbers:
[0246] Wet FGD systems have been the dominant worldwide technology
for the control of SOx from utility power plants. In the wet
scrubbing process, alkaline sorbent slurry is contacted with the
flue gas in a reactor vessel. The most popular wet scrubber reactor
is the spray tower design where the average superficial gas
velocity is less than the design gas velocity at maximum load. Flue
gas enters the scrubber module at a temperature of 250-350.degree.
F., and is evaporatively cooled to its adiabatic saturation
temperature by the slurry spray. The slurry consists of water mixed
with an alkaline sorbent: usually limestone, lime, magnesium
promoted lime, or sodium carbonate. Spray nozzles are used to
control the mixing of slurry with the flue gas. Sulfur dioxide is
absorbed by the liquid droplets and chemically converted to calcium
sulfite and calcium sulfate. These wet scrubber reactions usually
take place in the pH range of 5.5-7.0. The sulfur compounds formed
in this process are collected in the liquid film and deposited in
the reaction tank at the base of the scrubber. Forced oxidation is
often used in the reaction tank to oxidize the collected calcium
sulfite to calcium sulfate, which precipitates from the ionic
solution. If the calcium sulfate has sufficient purity, it can be
used as commercial gypsum (e.g. wallboard manufacture). Unreacted
reagents (dissolved in the ionic solution) are recirculated in the
sorbent slurry, increasing sorbent utilization.
[0247] Many factors determine the number of gas phase transfer
units (Ng) and SOx removal efficiencies. These factors include
slurry spray rate, slurry droplet size, spatial distributions, gas
phase residence time, liquid residence time, wall effects, and gas
flow distribution. In general, wet scrubbing is a highly efficient
SO.sub.2 control technology with removal levels >90% at
stoichiometric calcium/sulfur (Ca/S) ratios close to 1.0. Primary
advantages of this reliable, established technology include (1)
high utilization of sorbents and (2) the ability to produce usable
products: gypsum or sulfuric acid. The major disadvantages of wet
scrubbing are (1) complexity of operation, (2) limited control of
sulfur trioxide (SO.sub.3), (3) potential scaling and corrosion
problems, and (4) wet disposal products that typically require
dewatering, stabilization, and/or fixation.
[0248] b. Dry Scrubbers:
[0249] Dry scrubbing (sometimes referred to as spray absorption,
spray drying, or semi-wet scrubbing) is the principal alternative
to wet scrubbing for SOx control on solid-fuel combustion systems.
Dry scrubbing involves spraying a highly atomized slurry or aqueous
solution of alkaline reagent into the hot flue gas to absorb
SO.sub.2. Various alkaline reagents have been used in dry
scrubbers, but the predominant reagent used is slaked lime, which
behaves like highly reactive limestone. The quantity of water in
the atomized spray is limited so that it completely evaporates in
suspension. SO.sub.2 absorption takes place primarily while the
spray is evaporating. The dry scrubber reactions usually take place
in the pH range of 10-12.5. Apparently, this high alkalinity
contributes to the dry scrubber's effective removal of sulfur
trioxide (SO.sub.3) from the flue gas. The dry scrubber is noted to
quench the inlet flue gas to a temperature below the dew point for
SO.sub.3. Tests have indicated that virtually all S0.sub.3 is
absorbed and neutralized in the spray dry absorber. That is,
condensed sulfuric acid allegedly reacts with the alkaline sorbent
to form a collectible salt.
[0250] SOx dry scrubbers are designed to achieve the appropriate
reaction conditions for the specific alkaline reagent used:
temperature zone, mixing, residence time, and moisture. Dry
scrubbers are normally sized for a certain gas-phase residence time
(typically 8-12 seconds), which depends on the degree of
atomization and the design approach temperature. The approach
temperature is the difference between the adiabatic saturation
temperature and the temperature of flue gas leaving the dry
scrubber. Dry scrubbers are typically located immediately
downstream of the air preheater (flue gas temperatures
250-350.degree. F.), and upstream of the particulate control
device. The slurry spray adiabatically cools the flue gas.
Consequently, the flue gas temperature leaving the dry scrubber may
be too low for proper operation of the particulate control device.
In these instances, the gases may require heating before entering
the PCD (fabric filter or ESP). An electrostatic precipitator (ESP)
is more forgiving of temperature variation but the baghouse has the
advantage of being a better SOx-lime reactor.
[0251] Dry scrubber performance is primarily dependent upon reagent
stoichiometry and approach temperature. SOx removal efficiencies of
85-95% can be achieved with stoichiometric Ca/S ratios of 1.2-1.6
with solids recycle. The primary advantages of dry scrubbing over
wet scrubbing include (1) dry waste products, (2) greater S0.sub.3
control, and (3) less costly construction materials. Major
disadvantages include (1) high sorbent utilization rates, and (2)
potential reheating requirements. The high sorbent utilization
rates have limited dry scrubber applications to units burning
low-sulfur fuel. Dry scrubbers can increase particulate loading to
PCDs and waste disposal by 2-4 times.
[0252] c. Dry Sorbent Injection:
[0253] Furnace sorbent injection has been developed over the past
20-25 years. Dry sorbent technologies do not use reaction chambers,
but pneumatically inject alkaline reagents directly into the flue
gas at the location of appropriate temperatures for the desired
reactions. These dry sorbent technologies rely on the combustion
system to provide the mixing and residence time necessary to
achieve high conversion levels. These systems cost less, but
provide less SOx reduction capabilities. They can also increase
particulate loading to PCDs and waste disposal by 3-5 times due to
low sorbent utilization efficiency. Three major types of dry
sorbent injection appear promising:
[0254] 1. Furnace Injection of Calcium-Based Sorbents: Limestone,
dolomite, or hydrated lime readily reacts with SOx in the
temperature range of 2000-2300.degree. F. Normally, the injection
point for these sorbents is near the nose of the boiler. Using
these sorbents, 30-65% SOx removal is achievable with
stoichiometric calcium/sulfur (Ca/S) ratios of 2.
[0255] 2. Economizer Inlet and/or Post-Furnace Injection of Calcium
Hydroxide:
[0256] hydrated calcium hydroxide (Ca(OH).sub.2) favorably reacts
with SOx in the temperature range of 840-1020.degree. F. Injection
of this sorbent at the economizer inlet of many boilers can achieve
40-80% SOx capture with Ca/S=2. Alternatively, this sorbent can be
injected immediately downstream of the air heater with an
associated humidification system that increases relative humidity,
approaching the saturation temperature. With an approach
temperature of <50.degree. F., SOx capture of 50-55% can be
achieved with Ca/S=2. Since the sulfite formation is very fast
(<250 milliseconds) and the reaction window is approximately
212.degree. F. wide, the process is compatible with high quench
rates (typically 932-1112.degree. F./sec) through economizers.
[0257] 3. Post-Furnace Injection of Sodium-Based Sorbents: Trona
and nacholite (naturally occurring forms of sodium carbonate and
bicarbonates) react with SOx at air heater exit temperatures
(250-350.degree. F.). A relatively simple injection system is
placed between the air heater and baghouse. SOx reactions take
place in the flue ahead of the baghouse and on the surface of the
fabric filter. However, sodium carbonates have been observed to
catalyze the oxidation of nitric oxide (NO) to nitrogen dioxide
(NO.sub.2), which creates a visible, brown stack plume. SOx removal
efficiencies for nacholite are 70-80+% with sodium/sulfur ratio=1
(i.e. NSR =normalized stoichiometric ratio); Trona has demonstrated
45-70% removal with NSR Na/S=1. In both sorbents, lower overall
removal efficiencies are achieved with ESPs vs. fabric filters.
[0258] d. Other SOx Control Technologies:
[0259] Many other technologies are being evaluated for their
potential commercial application to address SOx control and acid
rain legislation/regulations. Considerable activity is being
devoted the development of a technology that effectively controls
both sulfur oxides and nitrogen oxides, with high removal
efficiencies and operational reliability. One such technology is
particularly relevant to the present invention: activated coke beds
for SOx and NOx control. The activated coke can adsorb SO.sub.2,
and catalyze the reduction of NOx by ammonia. Regeneration of the
spent coke at high temperature produces a concentrated SO.sub.2
stream that can be further processed to yield a salable by-product,
such as sulfuric acid. Such systems have been commercially applied
in Japan and Germany, where S02 removals of 90-99+% and NOx
removals of 50-80+% have been reported. However, most experience
has been with low- to medium-sulfur systems. There is some question
regarding process suitability for high-sulfur applications because
of high coke consumption.
[0260] e. Retrofit Applications:
[0261] Various types of dry scrubbing and dry sorbent injection
systems have been demonstrated on retrofit utility boiler
applications with baghouses or electrostatic precipitators. These
retrofit applications have usually added reaction chamber(s) and/or
injection system(s) upstream of existing particulate control
devices (PCDs) without significant increases in the PCD capacity.
That is, the PCD is not only required to control ash particulates,
but also handle the increased load of dry particulates resulting
from the conversion of sulfur oxides. These dry particulates
normally consist of ionic salts; spent sorbent and unreacted
sorbent. Typically, these salts are relatively large and easier to
collect than ash particulates. However, the combined load (Mlb/Hr.)
can be more than 200% of the original design. Consequently, this
type of dry scrubber retrofit can be limited by (1) ash particulate
inhibition of reagent reactivity and (2) capacity limiting effect
on PCD collection efficiency. Even so, numerous dry scrubber
retrofits have demonstrated SOx removal efficiencies between 85 and
90% with some sacrifice in particulate emissions. Similarly, dry
sorbent injection technologies have been demonstrated on retrofit
systems to achieve 40-70% with sacrifices in particulate emissions.
In general, these relatively low capital-cost alternatives can
effectively reduce sulfur oxide emissions. However, environmental
regulations for particulate emissions can be prohibitive for their
use as long-term solutions.
[0262] (3) Nitrogen Oxides (NOx) Control Fundamentals:
[0263] Nitrogen oxides emissions are formed in the combustion
process by two mechanisms: (1) Fuel NOx: oxidation of fuel-bound
nitrogen during fuel devolatilization and char burnout, and (2)
Thermal NOx: high-temperature oxidation of the nitrogen in the air.
Typically, more than 75% of the NOx formed during conventional PC
firing (i.e. w/o Low NOx Burners) is fuel NOx. Even though fuel NOx
is a major factor, only 20-30% of the fuel-bound nitrogen is
actually converted to NOx in uncontrolled conditions. Both NOx
formation mechanisms are promoted by rapid fuel-air mixing, which
produces high volumetric heat release rates, high peak flame
temperatures, and excess available oxygen. However, thermal NOx is
far more sensitive to high flame temperatures, particularly
>2200.degree. F. The potential reduction of nitrogen oxides
(NOx) emissions is site specific and depends on various combustion
design and operational factors.
[0264] a. Combustion Modifications:
[0265] Low NOx burners, staged combustion, flue gas recirculation,
and reburning are various types of combustion modifications used to
control the rate of fuel-air mixing, reduce oxygen availability in
the initial combustion zone, and decrease peak flame temperatures.
These combustion techniques can be used separately or in
combination to reduce thermal and fuel NOx. NOx reductions from
these methods typically range from 20 to over 60%. Low NOx burners
slow and control the rate of fuel-air mixing, thereby reducing
oxygen availability and peak flame temperatures in the ignition and
primary combustion zones. Staged combustion uses low excess air
levels in the primary combustion zone with the remaining (overfire)
air added higher in the furnace to complete combustion. Flue gas
recirculation reduces oxygen concentrations and combustion
temperatures by recirculating some of the flue gas to the furnace
without increasing total net gas mass flow. In reburning, 75-80% of
the furnace fuel input is burned in Cyclone furnaces with minimum
excess air. The remaining fuel (gas, oil, or coal) is added to the
furnace above the primary combustion zone. This secondary
combustion zone is operated substoichiometrically to generate
hydrocarbon radicals which reduce NOx formed in the Cyclone to
molecular nitrogen (N.sub.2). The combustion process is then
completed by adding the balance of the combustion air through
overfire air ports in a final burnout zone in the top of the
furnace.
[0266] b. Selective Non-Catalytic Reduction (SNCR):
[0267] In SNCR, ammonia or other compounds (e.g. urea) that
thermally decompose to ammonia are injected downstream of the
combustion zone in a temperature region of 1400 to 2000.degree. F.
If injected at the optimum temperature, the NOx in the flue gas
reacts with the ammonia to produce molecular nitrogen (N.sub.2) and
water. Without base-load operation, locating ammonia injection
system(s) at the optimal temperature is somewhat difficult due to
temperature variations with load swings and operational upsets. The
injection of hydrogen, cyanuric acid, or ammonium sulfate is
sometimes used to broaden the effective temperature range. NOx
reduction levels of 70% (from inlet concentrations) are possible
under carefully controlled conditions. However, 30-50% NOx
reductions are more typically used in practice to maintain
acceptable levels of reagent consumption and unreacted ammonia
carryover. Unreacted ammonia (often called ammonia slip) can (1)
represent additional pollutant emissions and (2) create ammonium
sulfate compounds that deposit on downstream heat exchange surfaces
and cause plugging, fouling, and corrosion problems.
[0268] c. Selective Catalytic Reduction (SCR):
[0269] SCR systems remove NOx from flue gases by reaction with
ammonia in the presence of a catalyst to produce molecular nitrogen
(N.sub.2) and water. Most SCR units can operate within a range of
450-840.degree. F, but optimum performance occurs between 675 and
840.degree. F. The minimum temperature varies and is based on fuel,
flue gas specifications, and catalyst formulation. NOx control
efficiencies of 70-90% can be consistently achieved. Like SNCR,
these control efficiencies are dependent on inlet NOx
concentrations, and are cumulative to NOx reductions from
combustion modifications. Also, the same concerns for unreacted
ammonia exist in SCR units.
[0270] d. Other NOx Control Technologies:
[0271] Other technologies are being evaluated for their potential
commercial application to address NOx control and acid rain
legislation/regulations. Considerable activity is being devoted the
development of a technology that effectively controls both nitrogen
oxides and sulfur oxides, with high removal efficiencies and
operational reliability. Most involve variations of reducing NOx
with ammonia, similar to SNCR and SCR. As noted above, activated
coke technology for the removal of SOx and NOx is particularly
relevant to the present invention.
[0272] (4) Carbon Dioxide (CO.sub.2) Control Fundamentals:
[0273] Environmental concerns of global warming have only recently
targeted carbon dioxide (CO.sub.2) as a flue gas component that
needs to be controlled. Consequently, control technologies for
carbon dioxide are currently in various stages of development. Wet
scrubbing and flue gas conversion to collectible particulates are
being evaluated for low-level control methods. High-efficiency
technologies include physical adsorption on activated media,
chemical solvent stripping, cryogenic fractionation, membrane
separation, and direct recovery from flue gas recirculation with
I.sub.2/CO.sub.2 combustion. Unfortunately, the disposal of
products from high-efficiency, non-regenerative control processes
becomes prohibitive due to the high levels of CO.sub.2 in the flue
gas. Consequently, most of the technologies are regenerative
producing a highly concentrated CO.sub.2 waste stream. Different
sequestering methods are being evaluated including deep ocean
injection, oil well injection, and biological fixation.
[0274] a. Wet Scrubbing:
[0275] Various types of reagents are being tried in conventional
wet scrubbing systems. Limited information and data have been
published to date.
[0276] b. Conversion to a Dry, Collectible Particulate:
[0277] Another approach being pursued is the, conversion of
CO.sub.2 to a dry particulate upstream of a particulate control
device. The alkaline reagents that convert sulfur oxides to dry
particulates are not as effective for carbon dioxide. Carbon
dioxide does compete with sulfur oxides for reactions with some SOx
dry scrubber reagents to a limited extent, and minor reductions are
achieved. However, carbon dioxide is more stable and is expected to
require a much stronger reagent, such as ammonia, sodium hydroxide,
and calcium hydroxide. At this point, concurrent conversion of both
sulfur oxides and carbon dioxide to particulate does not appear
likely due to a lack of reagent preference or selectivity for
carbon dioxide. Different temperature windows, residence times, and
reagents may be necessary. Consequently, conversion of carbon
dioxide to dry particulates may require independent systems with
different reagents, unless the fuel generates low levels of sulfur
oxides.
[0278] c. Adsorption on Activated Media:
[0279] The physical adsorption of CO.sub.2 on activated carbon or
zeolite systems is a surface phenomena in which a few layers of the
adsorbed gas are held by weak surface forces. The capacity of an
adsorbent for a given gas depends on the operating temperature and
pressure. The key issue for commercial application of these systems
is the surface area required per unit of mass or volume of adsorbed
gas. However, these systems are simple; their operation and
regeneration (pressure swing or temperature swing) can be
energy-efficient.
[0280] (5) Air Toxics Control Fundamentals:
[0281] Prior to the Clean Air Act Amendments (CAAA) of 1990, EPA
air toxics standards had been promulgated for only seven hazardous
air pollutants. In the CAAA's Title IlIl, EPA was required to
promulgate control standards for over 189 air toxic substances.
Consequently, control technologies for air toxics are currently in
various stages of development. Adsorption on activated carbon, wet
scrubbing, and flue gas conversion to collectible particulates are
three primary classes of technologies being considered.
[0282] (6) Solid Waste Control Fundamentals:
[0283] Solid wastes from fossil fuel combustion systems was
originally excluded from Subtitle C of the Resource Conservation
& Recovery Act (RCRA) of 1976, and still requires clarification
by U.S. federal regulations. In the meantime, high volume waste
streams from power plants, such as scrubber sludge, flyash, and
bottom ash are subject to different and highly variable disposal
requirements from state and local environmental and health
authorities. In addition, many landfills are required to use
leachate collection systems with single or double linings and
extensive monitoring wells. In some cases, stabilization of the
solids is required.
[0284] a. FGD Wet Scrubber Sludge:
[0285] In order to dispose of waste materials from wet collection
systems, treatment methods are applied to ultimately produce a
solid. Dewatering, stabilization, and fixation are common treatment
methods that are designed to achieve waste volume reduction,
stability, better handling, and/or liquid recovery for reuse.
Dewatering techniques physically separates water from solids to
increase solids content, and include settling ponds, thickeners,
hydroclones, and vacuum filters. Stabilization further increases
solids content of the waste by adding dry solids, such as flyash.
Fixation involves the addition of an agent, such as lime, to
produce a chemical reaction to bind free water and produce a dry
product.
[0286] b. Dry Solid Wastes:
[0287] Ultimate disposition of utility plant wastes (bottom ash,
flyash, FGD residues, etc.) is by utilization or by disposal in
landfills/impoundments. Utilization may be environmentally
preferred and becomes more attractive as waste management costs
increase. In some cases, bottom ash and boiler slag can be
substituted for sand, gravel, blasting grit, roofing granules, and
controlled fills. Flyash can also be utilized in the manufacture of
Portland cement and concrete mixes, if it meets certain minimum
quality specifications. In all utilization alternatives, the cost
of transportation can be prohibitive. Disposal methods can be
either wet or dry, depending on the physical condition of the waste
materials. The trend is toward dry disposal because of smaller
volumes, more options for site and material reclamation, and the
developing interest in dry scrubbing. Dry disposal can use a simple
method of landfill construction in which the waste is placed and
compacted to form an artificial hill.
[0288] E. Environmental Control of the Present Invention
[0289] The present invention does not claim the prior art
environmental control technologies separately, but provides
improvements and novel combinations of these technologies in
applications of the present invention. The different combinations
of these technologies are somewhat involved and provide synergism
and/or unappreciated advantages that are not suggested by the prior
art.
[0290] In most cases, fuel switching to the premium "fuel-grade"
petroleum coke of this invention provides the opportunity for
substantial improvements in the control of particulates, sulfur
oxides (SOx), nitrogen oxides (NOx), carbon dioxide (CO.sub.2), air
toxics, and opacity. In Table 2-B, uncontrolled pollutant emissions
of upgraded petroleum cokes are compared to the emissions of
various types of coal. The total quantity of undesirable flue gas
components (e.g. SOx) is typically lower than coals', even with
higher component concentration in the fuel (wt. % in pet coke vs.
coal). That is, sulfur, nitrogen, and carbon contents of the
upgraded coke are normally comparable or higher. Most of these
potential reductions in uncontrolled pollutants are related to the
significantly lower fuel rates and ash content of the upgraded
petroleum coke. In particular, the dramatic reduction in ash
particulates (>90%) creates tremendous excess capacity in the
existing particulate control device. This excess capacity can be
effectively used to collect other pollutants that have been
converted to collectible particulates upstream of the PCD. Finally,
none of these environmental improvements would be possible without
the fuel properties of the new formulation of petroleum coke that
allows utility boilers to burn up to 100% of this premium fuel.
[0291] (1) Conversion of Existing Particulate Control Devices:
[0292] The predominant environmental control feature in the present
invention is the potential use of existing particulate control
equipment for the control of sulfur oxides (SOx) and other
undesirable flue gas components. Since petroleum coke typically has
>90% less ash than most coals (i.e. 0.1-0.3% vs. 5-20%), a0
tremendous amount (90-95+%) of particulate control capacity in
existing particulate control devices is made available by fuel
switching (i.e. from coal to the upgraded petroleum coke). As such,
existing particulate control devices (baghouses, ESPs, etc.) can be
used for extensive removal of undesirable flue gas components by
converting them to collectible particulates upstream of these
devices.
[0293] The present invention can further increase the capacity of
the existing particulate control device by substantially reducing
fuel rates. That is, the upgraded petroleum coke has 10-200+%
greater heating value than most coals, which translates into
10-50+% reduction in fuel rates to achieve the same heat release
rate. The lower fuel rates and the associated reductions in air
flow rates o f t e n provide significant reductions in flue gas
flow rates. In an existing combustion system, any significant
reduction in flue gas flow rate increases flue gas residence time,
PCD capacity, and PCD control efficiency. These performance
parameters are strongly related to the flue gas flow rate and
velocities through the PCD collection media. For example, the ratio
of ESP plate area to volumetric flue gas flow rate is a critical
parameter in the Deutsch-Anderson Equation, which determines ESP
capacity and control efficiency. Similarly, the air-to-cloth ratio
(where air=flue gas flow in combustion sources) is a critical
parameter in equations that determine fabric filter capacity and
control efficiency. In this manner, the control efficiency in the
existing PCD is increased, providing a greater capacity to control
higher inlet loadings to the same particulate requirements for PCD
outlet.
[0294] Each combustion system will have a different set of design
conditions for converting the existing particulate control devices.
The conversion of each system will depend on various design and
operational parameters, but the optimal design and level of control
can be established with typical engineering skills associated with
the prior art of PCD technologies. Minor modifications may be
necessary to maintain particulate collection efficiencies. The
particulates coming into the existing PCDs may have substantially
different properties than the particulates of the PCD's design
basis. Consequently, modest modifications in design and/or
operating conditions may be required. For example, flue gas
conditioning or operational changes in existing ESPs may be
appropriate to achieve more desirable resistivity characteristics,
and maintain collection efficiencies.
[0295] (2) Flue Gas Conversion Technologies:
[0296] The present invention includes the integration of various
"flue gas conversion technologies" to control undesirable flue gas
components, and effectively use the excess particulate control
capacity created by the present invention. For the sake of this
discussion, "flue gas conversion technologies" refers to all
technologies that convert gaseous or liquid compounds in the flue
gas into chemical compounds (e.g. dry or wet particulates) that can
be effectively collected by particulate control technologies
(existing, new, or otherwise). Most of these technologies inject a
chemical reagent (wet or dry) that reacts with the targeted flue
gas component(s) and chemically converts them to compound(s) that
are particulates at the PCD operating conditions. Consequently,
this classification of environmental controls would include
commercially available SOx controls: wet scrubbing, spray dry
adsorption, and dry sorbent injection. The present invention
provides novel use and improvements in these and other flue gas
conversion technologies because of its unique ability to (1)
improve the reagent activity and utilization efficiency, (2)
provide the opportunity for reagent regeneration (and associated
improvements), (3) increase the probability of salable by-products,
and (4) promote the development of improved and new flue gas
conversion technologies (FGCT).
[0297] a. Reagent Activity & Utilization Efficiency:
[0298] The present invention provides less ash interference and
better recycle options to increase the reagent activity and
utilization efficiency in FGC processes. In many situations, the
flyash from the combustion process interferes with the reactions of
reagent and targeted flue gas component. The upgraded petroleum
coke of the present invention has very low ash content, which
substantially reduces interference and increases reagent activity.
This much lower flyash also allows extensive recycling of
conversion products, including unreacted reagents. For example, the
prior art in SOx dry scrubber technology processes and recycles
collected flyash into the reagent injection to increase reagent
usage. However, high ash particulates of existing fuels limit the
degree of recycling. The upgraded petroleum coke of the present
invention has such low ash particulates that greater quantities of
collected flyash (mostly FGCT products and unreacted reagents) can
be effectively recycled. The degree of recycle can be limited by
the capacity of the PCD, but recycle rates of 5-30+% are possible.
The optimal recycle rate can be developed for each application.
Both the reduced ash interference and the improved recycle
capabilities are expected to significantly increase reagent
utilization efficiencies and improve FGCT overall control
efficiencies and costs.
[0299] b. Opportunity for Reagent Regeneration:
[0300] The present invention provides the opportunity for
regeneration of FGCT reagents, due to very low ash and other
impurities in the collected flyash. That is, the collected flyash
consists mostly of FGCT products (or spent reagent) and unreacted
reagent. The collected flyash can be processed, and the spent
reagent can be regenerated to substantially reduce the make-up FGC
reagent rate and waste disposal required. The regeneration process
can include, but should not be limited to, hydration of the
collected flyash and subsequent precipitation of the undesired ions
(i.e. sulfates, carbonates, etc.) for commercial use or disposal.
Furthermore, the regeneration process would likely include a purge
stream of <30% (in some cases <5%) to remove unacceptable
levels of impurities from the system. This purge stream would be
analogous to blow down streams in many boiler water and cooling
water systems. In many cases, this purge stream will contain a high
concentration of heavy metals, including vanadium. Various physical
and/or chemical techniques can be used to extract and purify these
metals for commercial use. In cases where slaked lime is used as
the conversion reagent, the regeneration process can also greatly
reduce the carbon dioxide generated in the reagent preparation
process: limestone (calcium carbonate--CaCO.sub.4) to lime (calcium
oxide--CaO)+carbon dioxide (CO.sub.2). Finally, the ability to
continually regenerate reagents provides the opportunity for new or
improved flue gas conversion processes through the use of exotic
reagents; not considered previously due to costs. In this manner,
the regeneration of conversion reagents can (1) substantially
reduce reagent make-up and preparation costs (2) dramatically
reduce flyash disposal costs, (3) create a resource for valuable
metals, (4) reduce CO.sub.2 emissions, and (5) provide the means to
economically improve the flue gas conversion process via the use of
more exotic reagents.
[0301] c. Salable By-Products:
[0302] Whether or not the FGCT reagent is regenerated, the present
invention increases the probability of producing salable
by-products. The extremely low ash particulate levels create a
collected flyash that is mostly FGCT reaction products with low
impurities. As such, collected flyash from certain FGCTs can be
used as raw materials for various products, instead of solid wastes
requiring disposal. These products include, but are not limited to,
gypsum wallboard and sulfuric acid.
[0303] d. Development of Improved and New Conversion
Technologies:
[0304] The present invention can promote novel improvements and
development of many flue gas conversion technologies. Regeneration
with existing reagents can be developed for improvements of the
current sulfur oxides conversion technologies. Furthermore, all
these unique abilities of the present invention (i.e. efficient
reagent utilization, reagent regeneration, and salable by-products)
contribute to the development of new flue gas conversion
technologies for any undesirable flue gas components, including
sulfur oxides, carbon dioxide, nitrogen oxides, and air toxics. The
unique ability to regenerate conversion reagents, in particular,
opens the door to more exotic reagents that are more reactive,
selective, and/or costly to prepare. In the past, reagent selection
has been limited to very inexpensive materials due to disposable
nature (i.e. use once & throw away). With dramatically lower
impurities in the system, regeneration using novel conversion
reagents can be economically considered. That is, other alkaline
metal compounds with more desirable reaction characteristics or
by-products can be used without major economic consequences. For
example, ammonia and very reactive hydroxide forms of magnesium,
sodium, and/or calcium can be economically used as reagents in
FGCTs to control carbon dioxide, nitrogen oxides, and/or air
toxics. In addition, transportation costs for make-up reagent and
waste disposal can be dramatically reduced and help offset other
additional costs (e.g. regeneration system costs).
[0305] The integration of these flue gas conversion technologies is
anticipated by the present invention. That is, part of the benefits
of the present invention is to create excess particulate control
capacity in existing combustion systems that can be used in
conjunction with these technologies to achieve their objectives. In
this manner, The present invention provides a novel combination of
particulate control and flue gas conversion technologies,
particularly in retrofit applications on existing combustion
systems. These novel combined applications of existing
environmental technology provide substantial incentives to replace
existing solid fuels with the upgraded petroleum coke. However,
each combination of particulate control and flue gas conversion
technologies at existing combustion systems is a unique
application. One skilled in the art of these technologies is
capable of providing the appropriate design and operating
modifications required to achieve the successful implementation of
the desirable application of these combined air pollution control
technologies.
[0306] F. Environmental Impacts of an Exemplary Embodiment
[0307] In an exemplary embodiment of the present invention, an
existing utility boiler with a particulate control device is
modified by fuel switching: existing coal to premium "fuel-grade"
petroleum coke. The upgraded petroleum coke of the present
invention can be fired as the primary fuel (up to 100%).
Consequently, the very low ash particulate level generated from
such a fuel switch unleashes >90% of the existing PCD's capacity
to be used for flue gas conversion technologies (FGCT).
[0308] In this embodiment, two options are provided for the novel
integration of existing FGCT for the control of sulfur oxides.
Sulfur oxides control was chosen in this embodiment due to recent
emphasis related to acid rain legislation. However, FGCT for other
undesirable flue gas components can be implemented in a similar
manner. Option 1 consists of the addition of retrofit reaction
chamber(s) and reagent injection system(s) to convert sulfur oxides
to dry particulates upstream of the existing particulate control
device(s). Alternatively, Option 2 consists of the addition of dry
sorbent injection systems into and/or downstream of the furnace
section to convert sulfur oxides (or carbon dioxide) to dry
particulates upstream of the existing particulate control
device(s). An optimized combination of Options 1 and 2 can provide
the desired SOx control system in many cases (See Optimal
Environmental Control Embodiment).
[0309] As noted previously, all of these applications of flue gas
conversion technology (including SOx controls) are novel and unlike
any other commercial, retrofit applications. First, most flue gas
conversion applications have substantially higher ash particulates
in the flue gas. The ash particulates can interfere with the
reactivity of the injected reagents, potentially decreasing SOx
removal efficiencies. Secondly, previous utility retrofit
applications have used existing PCDs that are still operating at
>80% of capacity for ash collection and sacrifice particulate
emission levels. In contrast, the existing PCDs in this application
are operating at <10% of capacity for ash collection. This
design basis provides the opportunity to achieve much higher SOx
removal, while increasing (or maintaining) collection efficiency in
the PCD. Consequently, particulate emissions from the stack are
significantly less (or comparable). Finally, the very low ash
particulates cause the particulates collected by the PCD to be
predominantly spent reagent and unreacted reagent. The very low ash
and chloride content in the collected particulates provides a
greater ability to regenerate spent reagent (e.g. via hydration)
and/or recycle unreacted reagent from the collected particulates.
Consequently, substantially lower quantities of solids disposal
(e.g. purge stream) and fresh reagents for make-up requirements are
expected. Alternatively, the collected ash can have sufficient
purity to be used in the production of sulfuric acid, gypsum
wallboard, or other sulfate-based products. This alternative system
design can also substantially reduce the solids disposal
quantities. In conclusion, the combination of these factors makes
this application unique, and produces greater operating
efficiencies and more favorable economics.
[0310] The ultimate level of additional control for SOx and
particulates will depend on (1) the efficiency of conversion of the
sulfur oxides to particulates and (2) the efficiency of particulate
collection. In most utility boilers, reductions of over 70% in both
sulfur oxides and ash particulate emissions are expected.
[0311] (1) Particulate Impact:
[0312] The upgraded petroleum coke of the present invention
normally has over 90% less ash particulate emissions than most
coals for the same firing rate (See Table 2-B). This dramatic
reduction in ash particulates is primarily due to a much lower ash
content (0.1-1.0 wt. %). However, lower fuel rates (due to
significantly higher heating values) can also contribute greatly to
this reduction. The dramatic reduction in ash particulates
unleashes >90% of the capacity in the existing particulate
control device. This excess capacity can be used to collect other
pollutants that have been converted to collectible particulates
upstream of the PCD. In this manner, the fuel properties of the new
formulation of petroleum coke provide the opportunity to burn 100%
petroleum coke and use existing particulate control devices to
reduce the emissions of other pollutants, such as sulfur oxides,
nitrogen oxides, carbon dioxide, air toxics, etc.
[0313] In an exemplary embodiment, the overall particulate
emissions from the stack will depend on the ability to maintain
high collection efficiencies in the PCD. As noted above, the type
and quantity of particulates will be different due to fuel
switching and flue gas conversion technologies. For example, the
converted salts from the SOx dry scrubbing are normally larger and
easier to collect than ash particulates. Even though the ash
particulates are decreased dramatically, some breakthrough of
converted salts from flue gas conversion is expected. The quantity
of breakthrough will depend on the degree of flue gas conversion,
unreacted reagents, and the new collection efficiency. Besides the
increase in collection efficiency due to lower flue gas flow rates,
the products from SOx FGCT typically have characteristics that
increase particulate collection efficiency. For example, the
resistivity and drift velocity of calcium sulfate favor increased
ESP collection efficiencies. Though the application of FGCTs and
utilization of PCDs will vary substantially, the reduction in
overall particulate emissions from the stack is still expected to
be over 10%, in most cases. A significant reduction in PM-10
particulate (i.e. <10 microns) emissions is also expected.
[0314] (2) Sulfur Oxides Impact:
[0315] The predominant feature in this exemplary embodiment is the
potential use of existing particulate control equipment for the
control of sulfur oxides (SOx). Since petroleum coke typically has
>90% less ash than most coals (0.1-0.3% vs.
[0316] 20%), a tremendous amount (90-95+%) of particulate control
capacity in existing particulate control devices is made available
by fuel switching (from coal to the upgraded petroleum coke). As
such, the existing particulate control devices (baghouses,
electrostatic precipitators, etc.) can be used for extensive SOx
removal by converting the sulfur oxides to dry particulates
upstream of these devices.
[0317] In Option 1 of the exemplary embodiment of this invention,
retrofit reaction chamber(s) and reagent injection system(s) are
added to convert sulfur oxides to dry particulates upstream of the
existing particulate control device(s). As noted previously, 85-95%
SOx removal has been demonstrated by past utility retrofits of SOx
dry scrubber systems with substantially higher ash particulates in
the flue gas. For reasons noted above, the SOx dry scrubber
retrofit in the exemplary embodiment is expected to perform much
better. Consequently, 90% SOx removal efficiency is expected to be
a very conservative estimate for the potential reduction of SOx
emissions from the upgraded petroleum coke and Option 1 SOx control
of the exemplary embodiment.
[0318] In Option 2 of the exemplary embodiment, dry sorbent
injection systems are added to convert sulfur oxides to dry
particulates upstream of the existing particulate control
device(s). As noted previously, 40-70% SOx removal has been
demonstrated by past utility retrofits of SOx dry sorbent injection
systems with substantially higher ash particulates in the flue gas.
For reasons noted above, the dry sorbent injection retrofit in the
exemplary embodiment (Option 2) is expected to perform much better.
Consequently, 70% SOx removal efficiency is expected to be a very
conservative estimate for the potential reduction of SOx emissions
from the upgraded petroleum coke and Option 2 SOx control of the
exemplary embodiment.
[0319] In the past, the presence of vanadium has caused concern of
elevated dew points in the flue gas, due to its tendency to
catalyze the conversion of sulfur dioxide to sulfur trioxide. In
many situations, these elevated dew points can lead to increased
cold-end corrosion. However, the elevated dew points can have
positive impacts in the application of SOx flue gas conversion
processes. That is, the elevated dew points can provide more
favorable approach temperatures; improving collection efficiencies
while reducing water injection requirements. This is particularly
helpful in applications where the operating temperature of the
existing PCD is above the flue gas dew point; reducing the need for
flue gas reheat. In addition, tests have shown that SOx dry
scrubbing techniques perform better on sulfur trioxide (vs. sulfur
dioxide). Thus, the dry sorbent injection (Option 2), to some
extent, can be particularly beneficial to convert sulfur trioxide
to particulates in the convection section. In this manner, the
presence of vanadium can be advantageous upstream of
low-temperature heat exchange equipment. At the same time, the
catalytic conversion of SO.sub.2 to SO.sub.3 is also expected to
inhibit the formation of the highest oxidation level of vanadium;
vanadium pentoxide (V.sub.2O.sub.5). This reduction of vanadium
pentoxide further reduces associated ash problems. Finally, in
facilities with electrostatic precipitators, the sulfur trioxide
can also condition the flue gas and alter the resistivity
characteristics to improve the ESP's collection efficiency.
Consequently, certain levels of vanadium can improve the SOx
control systems.
[0320] The overall reduction of sulfur oxides due to fuel switching
and the retrofit flue gas conversion system is site specific and
depends on several factors. First, the lower fuel rates of the
upgraded petroleum coke can be sufficient to reduce SOx emission
rates (Mlb/Hr. or Mlb/MMBtu). This can occur even in cases where
the sulfur content (wt. %) of the upgraded petroleum coke exceeds
the sulfur content of the coal being replaced. Secondly, the sulfur
content of the upgraded petroleum coke can be lower than the sulfur
content of the replaced fuel. For example, low-sulfur petroleum
coke or desulfurized petroleum coke from hydrotreated coker
feedstocks can have significantly less sulfur (wt. %). In these
cases, the lower sulfur content, combined with lower fuel rates,
contributes to even greater reductions in sulfur oxides. Finally,
the retrofit of SOx dry scrubbing technology, in this exemplary
embodiment, is expected to reduce the inlet SOx emission rates by
90% or more. If the alternative dry sorbent injection systems are
used, the inlet SOx emission rates are expected to be reduced by up
to 70%. In some cases, the lower fuel rate and the sulfur content
of the upgraded petroleum coke are not sufficient to reduce the SOx
emission rate of the replaced fuel. However, the combination of the
lower fuel rate and the retrofit dry scrubbing can still produce
substantially lower SOx emissions (relative to various coals), even
when the coke sulfur content is much higher.
[0321] (3) Nitrogen Oxides Impact:
[0322] The upgraded petroleum coke of the present invention usually
has significantly less fuel-bound nitrogen due to the combination
of lower fuel rates and comparable nitrogen content, typically
0.5-1.5%. Thus, the fuel NOx is expected to be significantly less
or at least similar. Also, the flame intensity (and temperature
profile) of the upgraded coke is expected to be more uniform due to
lower VCM content and levelized burning profile. This uniform
temperature profile is expected to produce lower Thermal NOx than
most coals. The more uniform fuel characteristics of the upgraded
petroleum coke is also expected to reduce excess air requirements,
which lowers oxygen availability and typically lowers both fuel NOx
and thermal NOx. These and other combustion characteristics are
also conducive for the development of lower generation of nitrogen
oxides (NOx) emissions through Low NOx burner designs and other
combustion modifications. Consequently, the upgraded petroleum coke
of the present invention is expected to significantly decrease the
nitrogen oxide emissions of most coals, via fuel switching and
appropriate adjustments in Low NOx burner design and operation.
[0323] The application of SNCR, SCR, and/or FGCT for NOx is not
anticipated in this exemplary embodiment. However, if regulations
require additional NOx control, these technologies can be
integrated into the control alternatives of the exemplary
embodiment. The major concerns in the integration process are the
control priorities among pollutants and the potential conflicts
with other control technologies. That is, competitive or other
undesirable reactions (e.g. formation of ammonium bisulfate) can be
counterproductive in the combination of control technologies.
[0324] (4) Carbon Dioxide Impact:
[0325] Significant reductions in carbon dioxide emissions can be
achieved by methods similar to those for sulfur oxides emissions.
First, the carbon content of the upgraded petroleum coke can be
lower than the carbon content of the replaced fuel, but not
normally. Secondly, the lower fuel rates in most applications can
cause lower carbon dioxide emission rates. This can occur even in
cases where the carbon content (wt. %) exceeds the carbon content
of the coal being replaced. As shown in Table 2-B, this occurs in
almost every case. Finally, a retrofit, flue gas conversion system
can be used for modest to moderate carbon dioxide control, as well.
The combination of these factors will determine the overall
reduction in carbon dioxide resulting from fuel switching and the
retrofit, flue gas conversion system of the exemplary embodiment.
The potential for reduction from the retrofit CO.sub.2 flue gas
conversion is the most uncertain at this time.
[0326] An exemplary embodiment can effectively be used for flue gas
conversion of carbon dioxide, if and when the appropriate
temperature, residence time, and reagents become better understood
and available. As noted previously, flue gas conversion of carbon
dioxide is more likely without concurrent scrubbing of sulfur
oxides. Low-sulfur, petroleum coke, such as desulfurized coke, can
effectively improve the opportunity for carbon dioxide conversion
and collection. Table 2-A shows the desirable fuel properties of
desulfurized coke relative to various types of coals.
Alternatively, Option 2 dry sorbent injection system(s) can be used
for sulfur oxides control and the Option 1 retrofit reaction
chamber(s) and reagent injection system(s) can be used for the
control of carbon dioxide. In this case, the excess capacity of the
existing particulate control device can be the limiting factor.
Additional PCD capacity can be added as part of the retrofit
project to increase the carbon dioxide removal via flue gas
conversion processes.
[0327] (5) Air Toxics Impact:
[0328] The regulations regarding the levels of control required for
specific air toxics are still fairly unclear for utility boilers.
In general, though, the upgraded petroleum coke of the present
invention is expected to create less air toxic compounds, due to
its much lower ash content. This assumes that the combustion
process can achieve a high level of combustion efficiency and
destroy any hydrocarbon, classified as an air toxic compound. Flue
gas conversion technologies for air toxic compounds can also be
integrated, as necessary. Similar to other FGCTs, the major
concerns of integrating these processes are the control priorities
among pollutants and the potential conflicts with other control
technologies.
[0329] (6) Opacity Impact:
[0330] Opacity is an indication of the level of transparency in the
flue gases exiting the smokestack or the plume after moisture
dissipation. The level of opacity is primarily dependent on (1)
particulate concentration, (2) particle size distribution, (3)
sulfur trioxide concentration, and (4) moisture level. The use of
upgraded coke in this embodiment with either Option 1 or 2 for SOx
control is expected to significantly reduce the opacity level in
most utility boilers, due to the reductions in particulate and
sulfur trioxide concentrations in the flue gases, described above.
The reduced moisture and hydrogen content of the upgraded petroleum
coke (vs. most coals) can also contribute to lower opacity and
steam plumes. Finally, significant reductions in particulates less
than 10 microns can substantially improve the opacity.
[0331] (7) Solid Waste Impact:
[0332] As discussed previously, the upgraded petroleum coke of the
present invention can dramatically reduce the quantity and quality
of the solid wastes for disposal. The upgraded petroleum coke has
such low ash particulates that greater quantities of collected
flyash can be effectively recycled to increase reagent utilization
efficiencies. The improved reagent utilization often creates
greater proportions of the flyash as more stable compounds. For
example, the fully oxidized, spent reagent in SOX FGCT (calcium
sulfate) may be preferred for waste disposal (versus unreacted
reagent or less oxidized forms). Furthermore, the extremely low ash
particulate levels (i.e. low impurities) provide greater
opportunity to use the collected flyash as raw materials for
various products, instead of solid wastes, requiring disposal.
These products include, but are not limited to, gypsum wallboard
and sulfuric acid. In addition, the spent reagent can be
regenerated to dramatically reduce the wastes requiring disposal.
In this manner, flyash disposal and associated costs are
significantly reduced.
[0333] (8) General Issues:
[0334] Finally, none of these environmental improvements would be
possible without the fuel properties of the new formulation of
petroleum coke that allows the utility boilers to burn up to 100%
of this premium fuel. That is, the fuel properties of the upgraded
petroleum coke provide self-sustained combustion. Without it, these
environmental improvements would not be possible. The following
case study provides just one example of the benefits that can be
achieved with an exemplary embodiment of this invention.
G. EXAMPLE 1
Utility Boiler with Conventional Particulate Control Device
(PCD)
[0335] A power utility has a conventional, pulverized-coal fired,
utility boiler that currently burns medium-sulfur, bituminous coal
from central Ohio. The existing utility currently has a typical
particulate control device with no sulfur oxide emissions control.
Full replacement of this coal with a high-sulfur petroleum coke
produced by the present invention would have the following
results:
[0336] Basis=1.0.times.10.sup.9 Btu/Hr Heat Release Rate as
Input
1 Fuel Characteristics Results Current Coal Upgraded coke VCM (%
wt) 40.0 16.0 60% Lower Ash (% wt.) 9.1 0.3 97% Lower Moisture (%
wt.) 3.6 0.3 92% Lower Sulfur (% wt) 4.0 4.3 8% Higher Heating
Value (MBtu/lb) 12.9 15.3 19% Higher Fuel Rate (MIb/Hr) 77.8 65.4
16% Lower
[0337]
2 Pollutant Emissions: Uncontrolled/Controlled Ash Particulates
(lb/MMBtu or MIb/Hr) 7.1/0.4 .2/.01 97% Lower Sulfur Oxides
(lb/MMBtu or MIb/Hr) 6.2/6.2 5.6/.6 90% Lower Carbon Dioxide
(lb/MMBtu or MIb/Hr) 238 210 12% Lower
[0338] This example demonstrates major benefits from the
application of the present invention. The upgraded petroleum coke
has substantially lower ash and moisture contents, compared to the
existing coal. These factors contribute greatly to (1) the ability
to burn successfully with lower VCM and (2) a fuel heating value
that is 19% higher. In turn, the higher heating value requires a
16% lower fuel rate to achieve the heat release rate basis of one
billion Btu per hour in the boiler. As noted previously, this lower
fuel rate and the softer sponge coke significantly reduce the load
and wear on the fuel processing system, while increasing the
pulverizer efficiency and improving combustion characteristics.
[0339] The ash particulate emissions (ash from the fuel) are 97%
lower than the existing coal, due to the lower ash content and
higher fuel heating value. In this manner, fuel switching to the
upgraded coke unleashes 97% of the capacity in the existing
particulate control device. This excess capacity can now be used
for the control of sulfur oxides via retrofit flue gas conversion
technology.
[0340] A SOx dry scrubber injection/reaction vessel (option 1) is
added upstream of the existing particulate control device, along
with any associated reagent preparation and control systems. This
conversion of the existing particulate control device is assumed to
achieve 90% reduction in sulfur oxides in this case. Consequently,
the uncontrolled sulfur oxide emissions are reduced from 5.6 to
0.56 thousand pounds per hour. In this manner, the utility of
switching fuels and converting the existing particulate control
device to dry scrubbing represents 90% reduction in the coal's
sulfur oxides emissions (i.e. <0.6 vs. 6.2 lb/MMBtu). This
unexpected result is achieved even though the sulfur content (4.3%)
of the upgraded petroleum coke is 8% higher than the sulfur level
(4.0%) of the Ohio bituminous coal.
[0341] Alternatively, the dry sorbent injection systems (option 2)
could be used for sulfur oxides control. In this case, the inlet
SOx would be reduced by 70% (i.e. 5.6 to 1.7 Lb/MMBtu.). This
outlet SOx represents a 73% reduction in sulfur oxides emissions
from the bituminous coal. If this level of sulfur emissions is
sufficient to meet environmental regulations, the retrofit addition
of reaction chamber(s) and reagent injection system(s) is not
necessary. In this case, the use of retrofit flue gas conversion
technology for additional reductions of carbon dioxide is possible,
but not likely, due to lack of sufficient capacity in the existing
particulate control device. That is, the original ash particulate
capacity less the required capacity for converted SOx (large ionic
salts) may not leave sufficient capacity to make CO.sub.2 control
cost effective.
[0342] This example also illustrates significant reductions in
pollutant emissions, based solely on fuel switching. The 16% lower
fuel rate of the upgraded petroleum coke greatly contributes to
lower environmental emissions of ash particulates, sulfur oxides,
and carbon dioxide. The 97% reduction in ash particulates, noted
above, was primarily due to lower fuel ash concentration. However,
uncontrolled emissions of sulfur oxides and carbon dioxide are
significantly reduced primarily due to the 16% lower fuel rate.
That is, the sulfur content of the upgraded petroleum coke is 8%
higher than the existing coal. Yet the upgraded petroleum coke has
10% lower uncontrolled SOx. Similarly, the upgraded petroleum coke
has 5% higher carbon content (i.e. 87.5% vs. 83.3%). Yet the
uncontrolled emissions of carbon dioxide is reduced by 12% due to
fuel switching.
Other Embodiments & Ramifications
[0343] Other embodiments of the present invention may present
alternative means to achieve at least some of the objectives of the
present invention. Examples 2-5 are provided at the end of this
discussion to illustrate some of these embodiments of the present
invention.
[0344] 1. Production of Premium Pet Coke: Modified Fluid Coking.TM.
Process
[0345] Various operational changes in the Fluid Coking.TM. process
can produce a premium fuel-grade coke, in a manner similar to the
delayed coking discussion, above. Traditional Fluid Coking.TM.
normally produces a fuel-grade petroleum coke with higher metals
and sulfur content than delayed coke from the same feedstocks.
Fluid coke, like shot coke, is spherical in shape (170 to 220 um),
which makes it more difficult to grind. Its onion-like, laminated
layers of coke cause a much higher density and hardness (HGI
30-40). As such, Fluid coke is even less desirable as a fuel, when
compared to fuel-grade petroleum coke from the traditional delayed
coking process. Substantially less volatile combustible material
(4-8% VCM), much greater hardness, and much lower porosity are
three primary reasons. However, U.S. Pat. No. 4,358,290 discusses
the need to improve the combustion characteristics of fluid coke.
It discloses technology to increase the level of volatile
combustible material external to the coking process by blending the
fluid coke with heavy petroleum liquid. For reasons discussed
previously, leaving more VCM in the coke during the coking process
can be more desirable.
[0346] A. Traditional Fluid Coking.TM.; Process Description
[0347] FIG. 4 provides a basic process flow diagram for a typical
Fluid Coking.TM. process. The Fluid Coking.TM. process equipment is
essentially the same, but the operation, as discussed below, is
substantially different. Fluid Coking.TM. is a continuous coking
process that uses fluidized solids to further increase conversion
of coking feedstocks to cracked liquids, and reduce volatile
content of the product coke. Fluid Coking.TM. uses two major
vessels, a reactor 158 and a burner 164.
[0348] In the reactor vessel 158, the coking feedstock blend 150 is
typically introduced into the scrubber section 152, where it
exchanges heat with the reactor overhead effluent vapors.
Hydrocarbons that boil above 975.degree. F. are condensed and
recycled to the reactor with the coking feedstock blend. Lighter
overhead compounds 154 are sent to conventional fractionation and
light ends recovery (similar to the fractionation section of the
delayed coker). The feed and recycle mixture 156 is sprayed into
the reactor 158 onto a fluidized bed of hot, fine coke particles.
The mixture vaporizes and cracks, forming a coke film (.about.5 um)
on the particle surfaces. Since the heat for the endothermic
cracking reactions is supplied locally by these hot particles, this
permits the cracking and coking reactions to be conducted at higher
temperatures of about 510.degree. C.-565.degree. C. or (950.degree.
F.-1050.degree. F.) and shorter contact times (15-30 seconds)
versus delayed coking. As the coke film thickens, the particles
gain weight and sink to the bottom of the fluidized bed.
High-pressure steam 159 is injected via attriters and break up the
larger coke particles to maintain an average coke particle size
(100-600 um), suitable for fluidization. The heavier coke continues
through the stripping section 160, where it is stripped by
additional fluidizing media 161 (typically steam). The stripped
coke (or cold coke) 162 is then circulated from the reactor 158 to
the burner 164.
[0349] In the burner, roughly 15-25% of the coke is burned with air
166 in order to provide the hot coke nuclei to contact the feed in
the reactor vessel. This coke burn also satisfies the process heat
requirements without the need for an external fuel supply. The
burned coke produces a low heating value (20-40 Btu/scf) flue gas
168, which is normally burned in a CO Boiler or furnace. Part of
the unburned coke (or hot coke) 170 is recirculated back to the
reactor to begin the process all over again. A carrier media 172,
such as steam, is injected to transport the hot coke to the reactor
vessel. In some systems, seed particles (e.g. ground product coke)
must be added to these hot coke particles to maintain a particle
size distribution that is suitable for fluidization. The remaining
product coke 178 must be removed from the system to keep the solids
inventory constant. It contains most of the feedstock metals, and
part of the sulfur and nitrogen. Coke is withdrawn from the burner
and fed into the quench elutriator 174 where product coke (larger
coke particles) 178 are removed and cooled with water 176. A
mixture 180 of steam, residual combustion gases, and entrained coke
fines are recycled back to the burner.
[0350] B. Process Control of the Prior Art
[0351] In traditional Fluid Coking.TM., the optimal operating
conditions have evolved through the years, based on much experience
and a better understanding of the process. Operating conditions
have normally been set to maximize (or increase) the efficiency of
feedstock conversion to cracked liquid products, including light
and heavy coker gas oils. The quality of the byproduct petroleum
coke is a relatively minor concern. In "fuel-grade" coke
operations, this optimal operation detrimentally affects the fuel
characteristics of the coke, particularly VCM content, crystalline
structure, and additional contaminants.
[0352] As with delayed coking, the target operating conditions in a
traditional fluid coker depend on the composition of the coker
feedstocks, other refinery operations, and the particular coker's
design. The desired coker products also depend greatly on the
product specifications required by other process operations in the
particular refinery. That is, downstream processing of the coker
liquid products typically upgrades them to transportation fuel
components. The target operating conditions are normally
established by linear programming (LP) models that optimize the
particular refinery's operations. These LP models typically use
empirical data generated by a series of coker pilot plant studies.
In turn, each pilot plant study is designed to simulate the
particular coker design, and determine appropriate operating
conditions for a particular coker feedstock blend and particular
product specifications for the downstream processing requirements.
The series of pilot plant studies are typically designed to produce
empirical data for operating conditions with variations in
feedstock blends and liquid product specification requirements.
Consequently, the fluid coker designs and target operating
conditions vary significantly among refineries.
[0353] In normal fluid coker operations, various operational
variables are monitored and controlled to achieve the desired fluid
coker operation. The primary operational variables that affect coke
product quality in the fluid coker are the reactor temperature,
reactor residence time, and reactor pressure. The reactor
temperature is controlled by regulating (1) the temperature and
quantity of coke recirculated from the burner to the reactor and
(2) the feed temperature, to a limited extent. The temperature of
the recirculated coke fines is controlled by the burner
temperature. In turn, the burner temperature is controlled by the
air rate to the burner. The reactor residence time (i.e. for
cracking and coking reactions) is essentially the holdup time of
fluidized coke particles in the reactor. Thus, the reactor
residence time is controlled by regulating the flow and levels of
fluidized coke particles in the reactor and burner. The reactor
pressure normally floats on the gas compressor suction with
commensurate pressure drop of the intermediate components. The
burner pressure is set by the unit pressure balance required for
proper coke circulation. It is normally controlled at a fixed
differential pressure relative to the reactor. The following target
control ranges are normally maintained in the fluid coker for these
primary operating variables:
[0354] 1. Reactor temperatures in the range of about 950.degree. F.
to about 1050.degree. F.,
[0355] 2. Reactor residence time in the range of 15-30 seconds
[0356] 3. Reactor pressure in the range of about 0 psig to 100
psig: typically 0-5 psig,
[0357] 4. Burner Temperature: typically 100-200.degree. F. above
the reactor temperature
[0358] These traditional operating variables have primarily been
used to control the quality of the cracked liquids and various
yields of products, but not the respective quality of the byproduct
petroleum coke.
[0359] C. Process Control of the Present Invention
[0360] The primary improvements of the present invention are
modifications to the operating conditions of the Fluid Coking.TM.
process, in a manner that is not suggested by prior art. In fact,
these changes in operating conditions are contradictory to the
teachings and current trends in the prior art. As noted previously,
the operating conditions of the prior art give first priority to
maximizing cracked liquid products. The operating conditions of the
present invention give first priority to consistently increasing
the volatile combustible material in the resulting petroleum coke
to 13-50 wt. % VCM (preferably 15-30% VCM). Second priority is
given to consistently provide a minimum-acceptable level of coke
crystalline structure in the product coke. The third priority is
THEN given to maximize coker throughput and/or the conversion of
coker feedstock blend to cracked liquid products. However, changing
the VCM content and crystalline structure in fluid coke is much
more challenging, relative to delayed coke. The operating
conditions required to achieve the objectives of the present
invention were moderate, yet specific changes relative to the prior
art.
[0361] As discussed previously, fluid coker operating conditions
vary greatly among refineries, due to various coker feedstocks,
coker designs, and other refinery operations. Therefore, specific
operating conditions (i.e. absolute values) for various refinery
applications are not possible for the present invention. However,
specific changes relative to existing operating conditions provide
specific methods of operational change to achieve the desired
objectives.
[0362] (1) Increased Volatile Combustible Material (VCM) in Fluid
Coke:
[0363] In a manner similar to the delayed coking process, reduction
in the process operating temperature will cause an increase of
volatile combustible material in the resulting petroleum coke. That
is, the reduction in process (or reactor) temperature will reduce
the cracking and coking reactions, and thereby, leaving more
unreacted coker feedstock and cracked liquids in the coke as
volatile combustible material. However, the different mechanism of
coking in the Fluid Coking.TM. process may require a more
significant reduction in temperature to achieve the same level of
VCM in the petroleum coke. In the Fluid Coking.TM. process, the
temperature of the fluidized coke particles leaving the coke burner
would be the primary temperature to reduce. Decreasing this
temperature by 10-200.degree. F. (preferably 10-80.degree. F.) can
increase the fluid coke VCM to the preferable range of 15-30%.
Reduction of feed temperature and the operating temperature of the
reactor would also play secondary roles in increasing the VCM on
the petroleum coke. However, if the reactor temperature is too low,
the fluid coker will bog down and lose fluidization. If the reactor
temperature (in a particular fluid coker) approaches this bogging
condition prior to achieving the desired VCM increase, other
operational parameters can be modified to achieved the desired VCM.
The reduction of coke stripping and the addition of oily
sludges/substances or hazardous wastes in the final quench of the
product coke can provide the additional VCM required.
[0364] The reduction of coke stripping at the base of the fluid
coker reactor can also increase the product coke VCM. The reduced
efficiency of the stripping section will leave more VCM on the cold
coke circulated to the burner. In the burner, less coke (i.e.
higher VCM coke) would be burned to provide the same heat
requirements. Consequently, a greater yield of higher VCM product
coke would be produced.
[0365] The addition of oily sludges (or other oily substances) or
hazardous wastes in the final quench of the product coke can also
provide the additional VCM required. Similar to the delayed-coke
drum quenching process, the quenching of product (fluid) coke in
the quench elutriator can be used to achieve the desirable VCM
content. That is, oily sludges or other oily substances, such as
used lubricating oils, can be added to the quench water to leave
more VCM on the fluid coke product. Various types of hazardous
wastes can be used as a raw material (vs. waste) in this modified
process, instead of underground injection or less desirable
disposal methods. However, environmental regulations may require a
delisting process or other means of dealing with the hazardous
waste requirements. This method can be effective in evenly
distributing quench material throughout the coke, and provide
various options regarding the quality of VCM content. This option
is discussed further in other embodiments.
[0366] (2) Acceptable Fluid Coke Crystalline Structure:
[0367] Unfortunately, operational changes in the fluid coker will
not significantly impact the crystalline structure of the product
fluid coke. The fluid coke has onion-like, laminated layers of coke
due to the nature of the Fluid Coking.TM. process. As such, the
product fluid coke has the consistency of coarse sand (vs. sponge)
with a much higher density and much lower porosity. Consequently,
the high VCM coke can have limited utility and can be limited to
applications where the current crystalline structure is acceptable.
Also, this denser crystalline structure may require higher VCM
quality and quantity versus sponge coke.
[0368] D. Low-Level Decontamination of Coker Feedstocks:
[0369] Desalting Operations
[0370] As in the exemplary embodiment, the three-stage desalting
operation will provide the simplest and best known approach to
provide the low-level decontamination of the product fluid coke
required for combustion applications. The low-level decontamination
of the feedstocks will have similar effects in the fluid coker. The
three-stage desalting operation will minimize (or substantially
reduce) the sodium content of the fluid coke. This sodium reduction
is expected to be sufficient to prevent the formation of
undesirable sodium compounds in the combustion process. However,
the reduction of vanadium and other metals may not be as effective.
The Fluid Coking.TM. process tends to concentrate more of these
materials in the product fluid coke.
[0371] 2. Production of Premium "Fuel-Grade" Pet Coke: Additional
Embodiments
[0372] Additional embodiments of the various means to produce a
premium "fuel-grade" petroleum coke are described below. Any, all,
or any combination of the embodiments, described above or below,
can be used to achieve the objects of this invention. In any
combination of the embodiments, the degree required may be less
than specified here due to the combined effects.
[0373] A. Control of VCM in the Petroleum Coke; Additional
Embodiments
[0374] (1) Delayed Coking; Other Process Variables:
[0375] In the delayed coking process, other process parameters
could also be modified to achieve the desired level of VCM on the
petroleum coke. That is, operational control variables other than
feed heater outlet temperatures may be modified to achieve the
major objectives of the present invention and/or more optimal
operation for a particular refinery. These other operational
control variables may include, but should not be limited to, the
coker feedstock blend, drum pressure, hat temperature, cycle time,
recycle rate, and feed rate. Modifications to these operational
variables may or may not accompany a decrease in the feed heater
outlet temperature. Process variables that increase the thermal
coking mechanism (such as feedstock modifications) would be
preferable; increasing sponge coke as well as VCM. Coker feedstock
pretreatment (e.g. hydrotreating) has also been noted to increase
coke VCM, in certain situations. In addition, this embodiment
anticipates (1) various combinations of process variable
modifications and (2) different control priorities (for meeting
various product specifications) that also achieve the major
objectives and basic intent of the current invention.
[0376] (2) Fluid Coking.TM.; Other Process Variables:
[0377] In a similar manner, other process parameters of the Fluid
Coking.TM. process could also be modified to achieve the desired
level of VCM on the petroleum coke. Operational control variables,
other than Fluid Coking.TM. reactor temperature, may be modified to
achieve the same object for more optimal operation for a particular
refinery. These other operational control variables may include,
but should not be limited to, the coker feedstock blend, feed rate,
reactor pressure, reactor residence time, and recirculated coke
particle size. Coker feedstock pretreatment (e.g. hydrotreating)
can increase coke VCM, in certain situations. Modifications to
these operational variables may or may not accompany a decrease in
reactor temperature, recirculated coke fines temperature and/or
feed temperature. In addition, this embodiment anticipates (1)
various combinations of process variable modifications and (2)
different control priorities (for meeting various product
specifications) that also achieve the major objectives and basic
intent of the current invention.
[0378] (3) Flexicoking.TM., Changes in Process Variables:
[0379] A case could be made for increasing the VCM and/or improving
crystalline structure of the purge coke in Flexicokin Process
changes would be similar to the process changes made in Fluid
Coking.TM., due to their similar design basis. However, the
additional coke devolatilizing in the Flexicoking.TM. process make
the increased VCM more difficult. Furthermore, higher VCM coke
would not likely have substantial utility, since Flexicoking.TM.
consumes most of its coke internally in its gasifier.
[0380] (4) Reduced Stripping of Product Coke:
[0381] In another embodiment, less stripping of the product coke
may provide part (or all) of the desired increase in the volatile
combustible material in the petroleum coke. Reducing the steaming
of the product coke will significantly decrease the liquid
hydrocarbons removed from the coke, via vaporization and/or
entrainment. Thus, the VCM content of the product coke is
increased. Most of the VCM increase is expected to be cracked
liquids with boiling temperatures <1000.degree. F. This can
effectively improve the quality as well as the quantity of VCM on
the petroleum coke. This embodiment can be applicable to the coke
stripping in delayed coking, Fluid Coking.TM., Flexicoking.TM., and
other types of coking processes, available now or in the future. In
delayed coking, an added benefit is the potential for a significant
reduction in the decoking cycle. The elimination of the initial
steam-cooling step in the decoking procedure could help decrease
decoking cycle time by up to 3 hours.
[0382] (5) Injection of Oily Sludges/Fluids in Coke Quench:
[0383] In another embodiment, various oily sludges or other fluids
containing hydrocarbon substances (e.g. used lubricating oils) can
be used in the quench for the product coke to increase its VCM. The
method of introducing the oily sludges/fluids may be similar to
that described in U.S. Pat. No. 3,917,564 (Meyers; 11/4/1975).
However, the injection of hydrocarbons in the quench may continue
until the coke temperature reached 250-300.degree. F. (vs.
450.degree. F.). This modified method would allow high quality VCMs
(boiling ranges of 250-850.degree. F. and heating values of
16-20,000 Btu/lb) to be evenly dispersed on the upgraded petroleum
coke. Another improvement may also include the introduction of the
oily sludges/fluids without the two initial steam cooling steps, to
reduce decoking cycle time and leave more VCM on the petroleum
coke. A further improvement would result from segregating the
hydrocarbon substances by boiling ranges and inject them with the
quench at the appropriate cooling stage to vaporize the water
carrier, but not the hydrocarbon fluids. That is, an exemplary
method may inject the water quench (without initial steam cooling)
in stages that maintains coke temperatures below the boiling ranges
of the segregated hydrocarbon substances it contains. In addition,
the injection of the quench in the top of the drum (or other
locations) may provide further advantage to condense escaping VCM
vapors that are entrained in the steam or vaporized by localized
hot spots in the coke drum. The optimization of these methods for
particular refineries would maximize (or substantially increase)
retention of these oily substances integrated in the upgraded
petroleum coke.
[0384] Most of the VCM increase is expected to come from unreacted
hydrocarbons. The degree of VCM from 1000.degree. F.+ materials
will depend on the type of sludges or oily substances. If oily
substances are chosen to produce VCM <850.degree. F., this
embodiment can improve the quality as well as the quantity of the
VCM. In addition, the resulting fuel-grade petroleum coke is
expected to be less sensitive to the disposal of various sludges
and oily substances, when compared to similar disposal methods for
other grades of petroleum coke. However, certain sludges can add
significant ash content and undesirable contaminants, such as
sodium, to the product coke. This embodiment can be applicable to
the coke quenching in delayed coking, Fluid
Cokin.TM.,Flexicoking.TM. and other coking processes, available now
or in the future.
[0385] (6) Injection of Oily Sludges/Fluids in Coking Process:
[0386] In another embodiment, various oily sludges or other fluids
containing oily substances (e.g. used lubricating oils) can be
introduced into other parts of the coking process (e.g. coker
feedstocks) to increase the product coke VCM. The method of
introducing the oily sludges/fluids may be similar to that
described in U.S. Pat. No. 4,666,585 (Figgins & Grove; May 19,
1987). However, the oily sludges in this application would be
segregated to give first priority to oily sludges that are
predominantly hydrocarbons with boiling ranges exceeding
600-700.degree. F. The introduction points in the delayed coking
process should include, but not be limited to coker feedstock,
fractionator, coke drum, and other streams prior to coking.
Similarly, introduction points in the Fluid Coking process should
include, but not be limited to, coker feedstock, feed heater,
scrubber section, coker reactor, and other streams prior to
coking.
[0387] Similar to coker feedstocks, the VCM increase is expected to
come from unreacted materials and cracked liquids. The degree of
VCM from 1000.degree. F.+ materials will again depend on the type
of sludges or oily substances. As above, the resulting fuel-grade
petroleum coke is expected be less sensitive to the disposal of
various sludges and used lubricating oil, when compared to similar
disposal methods for other grades of petroleum coke. Similarly,
certain sludges can add significant ash content and undesirable
contaminants, such as sodium, to the product coke. This embodiment
can be applicable to delayed coking, Fluid Coking.TM.,
Flexicoking.TM. and other coking processes, available now or in the
future.
[0388] (7) Injection Oo Hazardous Wastes in Coking Process or Coke
Quench:
[0389] Various types of hazardous wastes can be injected as a raw
material or chemical feedstock (vs. waste) in this modified
process. Selective use of hazardous wastes with desirable
volatilization and combustion properties (e.g. predominantly
hydrocarbons) can greatly improve the quality of the upgraded
petroleum coke's VCM. At the same time, the hazardous wastes could
be effectively used in this product, instead of underground
injection or less desirable disposal methods. In some cases, the
EPA delisting or other process may be required to address
environmental regulations regarding hazardous wastes. In many
cases, the concentration of the hazardous waste in the resulting
coke would be sufficiently low to minimize (or greatly reduce)
hazardous waste characteristics.
[0390] The addition of hazardous wastes in the coking reaction (via
blending with coker feedstock or other injection points) can
provide a cost-effective source of VCM for the resultant coke with
limited reductions in cracked liquid production. The method of
introducing the hazardous wastes in the delayed coking cycle may be
similar to that described in U.S. Pat. No. 4,666,585 (Figgins &
Grove; May, 19, 1987). However, the hazardous wastes in this
application may be segregated to give first priority to oily
sludges that are predominantly hydrocarbons with boiling ranges
exceeding 600-700.degree. F. The introduction points in the delayed
coking process should include, but not be limited to coker
feedstock, fractionator, coke drum, and other streams prior to
coking. Similarly, introduction points in the Fluid Coking process
should include, but not be limited to, coker feedstock, feed
heater, scrubber section, coker reactor, and other streams prior to
coking.
[0391] Injection in the coke quench, however, may be preferable to
increase the quantity of VCM with low boiling points (i.e.
250-850.degree. F.), remaining with the coke (vs. overhead product
as cracked liquid). Consequently, this higher quality VCM would
enhance the ignition and combustion characteristics of the upgraded
coke. Injection via coke quench can be effective in evenly
distributing quench material throughout the coke. The method of
introducing the hazardous wastes in the coke quench may be similar
to that described in U.S. Pat. No. 3,917,564 (Meyers; Nov. 4,
1975). However, the injection of hazardous wastes in the quench
would continue until the coke temperature reached 250-300.degree.
F. (vs. 450.degree. F.). This modified method would allow high
quality VCMs (boiling ranges of 250-850.degree. F. and heating
values of 16-20,000 Btu/lb) to be evenly dispersed on the upgraded
petroleum coke. Another improvement may also include the
introduction of the hazardous wastes without the two initial steam
cooling steps, to reduce decoking cycle time and leave more VCM on
the petroleum coke. A further improvement would result from
segregating the hydrocarbon substances by boiling ranges and inject
them with the quench at the appropriate cooling stage to vaporize
the water carrier, but not the hydrocarbon fluids. That is, an
exemplary method may inject the water quench (without initial steam
cooling) in stages that maintains coke temperatures below the
boiling ranges of the segregated hydrocarbon substances it
contains. In addition, the injection of the quench in the top of
the drum (or other locations) may provide further advantage to
condense escaping VCM vapors that are entrained in the steam or
vaporized by localized hot spots in the coke drum. The optimization
of these methods for particular refineries would maximize (or
substantially increase) retention of these oily substances
integrated in the upgraded petroleum coke. Similar results are
expected for many types of hazardous wastes.
[0392] (8) Combination of Embodiments to Achieve Desirable Burning
Profile:
[0393] As noted previously, the end-users' VCM specification can be
lowered by providing the optimal burning profile for his combustion
system design. That is, the VCM increase can preferably be a
combination of hydrocarbons with various boiling ranges. To a
certain extent, the burning profile of the petroleum coke can be
adjusted by a combination of the above embodiments. For example,
most of the VCM increase can come from a decrease in heater outlet
temperature and the addition of used lubricating oils to the coker
feed, with most VCM >1000.degree. F. materials. The remainder of
the VCM could come from reduced steaming and using oily sludges in
the quench, producing VCM with lower boiling ranges (e.g.
350-1000.degree. F.). These lower boiling range VCM would improve
flame initiation, stability, and intensity. Consequently, the types
of volatile combustible materials could be varied to a reasonable
degree, based on pilot studies for production and burning of
petroleum coke. In this and similar approaches, the formulation of
petroleum coke can be custom-made to match (to the extent possible
and reasonable) the burning profile of the end-user's combustion
system. In this manner, the end-user can optimize the operation of
his combustion system without expensive design modifications to
accommodate the fuel switch to petroleum coke. Consequently, this
approach is conducive to achieving the lowest VCM required by the
end-user's current combustion system.
[0394] (9) Genral Issues for Various Embodiments of VCM
Control:
[0395] As noted above, the use of less stripping and/or quench
containing hydrocarbons can eliminate or reduce the need for
additional VCM from the coker feedstock. However, the petroleum
coke VCM must be able to endure the weathering (rain, snow, etc.)
in transport and storage, and provide the VCM required by the
end-user at its facility. That is, VCM from lighter hydrocarbons
may be lost from the product coke, due to higher solubility and
continual washing.
[0396] After the specific level and types of VCM required are
determined for any given product coke, engineering factors will
determine the optimal use for any of the above embodiments,
separately or in combination, for a particular refinery. In any
combination of the embodiments, the degree required may be less
than specified here due to the combined effects. Finally, these
concepts and embodiments may be applied to other types of coking
processes, available now or in the future.
[0397] As noted previously, the main objective of the present
invention is to achieve a petroleum coke with acceptable VCM,
crystalline structure, and decontamination levels, preferably
specified by the end-user. THEN, the conversion of coker feedstock
blend to lighter liquid products is maximized. Optimization of all
operating conditions and economic constraints via refinery LP
computer models is anticipated. However, this model would likely
include a petroleum coke product having the end-user specified VCM,
crystalline structure, and decontamination levels as operational
constraints.
[0398] B. Control of Petroleum Coke Crystalline Structure;
Additional Embodiments
[0399] (1) Other Coker Operating Variables:
[0400] In coking processes, other process parameters could also be
modified to achieve the desired level of crystalline structure
within the petroleum coke. Operational control variables other than
drum and coke recirculation temperatures may be modified to achieve
the same object or more optimal operation for a particular
refinery. These other operational control variables would
preferably increase the thermal coking mechanism and/or decrease
the asphaltic coking mechanism to bring R-values down to an
acceptable level. For delayed cokers, these other operational
control variables may include, but not be limited to, the coker
feedstock blend, fractionator pressure, hat temperature, cycle
time, and feed rate. For Fluid Coking.TM., these other operational
control variables may include, but not be limited to, the coker
feedstock blend, solids circulation rate, fractionator pressure,
and feed rate. Modifications to these operational variables may or
may not accompany a decrease in the outlet temperatures of the
respective feed heaters or other operating temperatures. Process
variables that increase VCM while decreasing shot coke would be
preferable.
[0401] (2) Coker Feedstock Modifications:
[0402] Coker feedstocks could also be modified to achieve the
desired level of crystalline structure within the petroleum coke.
That is, feedstock modifications can achieve the same object or
more optimal operation for a particular refinery. These would
preferably increase the thermal coking mechanism and/or decrease
the asphaltic coking mechanism to bring R-values down to an
acceptable level. Coker feedstock modifications could include, but
not be limited to (1) dilution with fluids/feedstocks with less
asphaltene and resins content, (2) the addition of highly aromatic
feedstocks, such as FCCU slurry oil, and/or (3) coker feed
pretreatment (e.g. hydrotreating or other desulfurization). This
embodiment can be applicable to delayed coking, Fluid Coking.TM.,
Flexicoking.TM. and other coking processes, available now or in the
future.
[0403] (3) Coker Additives:
[0404] Various chemical and/or biological agents could be added to
the coking process to further help inhibit the formation of shot
coke and/or promote the formation of desirable sponge coke. One
such additive may inhibit the role certain contaminant particles
play in the formation of shot coke. Also, U.S. Pat. No. 4,096,097
(Yan: Jun. 20, 1978) describes a method for inhibiting shot coke
and promoting sponge coke formation for the production of an
electrode grade petroleum coke having desired grindability
qualities. This method comprises adding an effective amount of
oxygen-containing, carbonaceous material (which tends to decompose
at high temperatures) to the delayed coker and/or recycle/feed. The
addition of oxygen-containing carbonaceous material, in combination
with other features of the present invention, may further help
eliminate or substantially reduce shot coke formation and promote
sponge coke crystalline structure. Examples of the
oxygen-containing carbonaceous material include, but are not
limited to, sawdust, newspaper, alfalfa, wheat pulp, wood chips,
wood fibers, wood particles, ground wood, wood flour, wood flakes,
wood veneers, wood laminates, paper, cardboard, straw, cofton, rice
hulls, coconut shells, peanut shells, plant fibers, bamboo fibers,
palm fibers, kenaf, bagasse, sugar beet waste, coal (e.g.,
subbituminous coal), lignite, other cellulosic materials and
wastes, other oxygen-containing carbonaceous materials, and other
materials having similar characteristics. The carbonaceous material
preferably has an oxygen content in the range of from about 5% to
about 60% by weight. However, it should be recognized that
carbonaceous materials having an oxygen content outside of this
range may also be used in the present invention.
[0405] The inventor has also made the surprising discovery that the
addition of other chemical agents, with or without an oxygen
content in the range of from about 5 to about 60 wt. %, can further
promote the production of sponge coke and eliminate or
substantially reduce shot coke formation. While not wanting to be
bound by any particular theory of operability, these other chemical
agents tend to increase porosity by producing lighter gases (i.e.,
Molecular Weight <50) that rise through the coking mass in the
petroleum coking process. This theory of operability is similar to
foaming agents for plastics, such as polystyrene, and to the method
of adding oxygen-containing carbonaceous materials to the delayed
coker and/or recycle/feed. The production of these lighter gases
can be caused by various mechanisms. These mechanisms include, but
are not limited to, (1) the decomposition of the chemical agents at
petroleum coking process conditions (e.g., thermal cracking) and
(2) other chemical reactions in the coking process.
[0406] It should, however, be recognized that the current invention
is not limited to adding carbonaceous chemicals and/or chemicals
that contain about 5 to about 60% oxygen by weight. As noted above,
the carbonaceous material and/or chemicals may have an oxygen
content outside of this range and still promote the production of
sponge coke and eliminate or substantially reduce shot coke
formation. Furthermore, the lighter gases are not limited to those
containing oxygen (e.g., CO.sub.2, H.sub.2O, etc.). In fact, for
reasons described below, the preferred lighter gases released by
the decomposition of the chemical agents may be hydrogen, methane,
propane, and other light hydrocarbons. Finally, the chemical agents
do not necessarily have to be carbonaceous materials. That is, the
chemical agents do not have to contain carbon (i.e., organic) as
long as they meet certain criteria in their decomposition at the
coking process conditions.
[0407] The chemical agents of the current invention may have unique
and improved features over the oxygen-containing, carbonaceous
materials. The exemplary chemical agents may have some or all the
following characteristics:
[0408] 1. Release (1) hydrogen, (2) light hydrocarbons (C.sub.3--),
(3) other light gases without oxygen, and/or (4) light gases with
oxygen upon decomposition in the coking process conditions
[0409] a. Promote high-porosity sponge coke (vs. shot coke):
Increase porosity, improve carbon adsorption character, and improve
grindability properties; Proposed mechanisms include, but are not
limited to:
[0410] 1. The light gases, under pressure, pass through the coke
mass creating voids in the developing petroleum coke crystalline
structure: The petroleum coke pore size is partially related to the
gas molecules' sizes. That is, smaller gas molecules lead to
smaller pore sizes. Thus, preferable adsorption character can be
effected by control of gas molecular size.
[0411] 2. Disturb crystal growth and prevent undesired coke
formation, particularly shot coke
[0412] 3. Limit petroleum coke crystal size due to nuclei of
certain agents, coupled with the proper aromatic-asphaltic ratio
established via lower drum temperatures
[0413] b. Quench the cracking/coking reactions via hydrogen
reaction with free radicals to break these endothermic, chain
reactions: prevents vapor overcracking and improves coker products,
as well as decreases the coke yield and improves coke quality (see
1a: 2 & 3)
[0414] c. Provide higher value coker off gas products: Hydrogen and
light hydrocarbons (versus oxygen-containing gases such as
CO.sub.2, H.sub.2O, etc.) pass through the coke and are used
further
[0415] 2. Tend to form valuable liquid hydrocarbon products from
decomposition in the coking process conditions: vs. greater than
50% coke yields of oxygen-containing carbonaceous materials (wood,
lignite, waste coals, etc.)
[0416] 3. Inexpensive & readily available in refinery area
(e.g., recycled or waste materials)
[0417] Examples of the chemical agents include, but are not be
limited to, various types of plastics, rubber, cardboard, and
paper. Recycle or waste streams may be used. The chemical agent
preferably has a particle size less than 100 mesh, and more
preferably less than 50 mesh. However, it should be recognized that
the chemical agent may have any particle size that enables it to
provide desirable results. Alternatively, the chemical agent can be
injected into the coking process in forms other than fine
particulates. For example, the injected chemical agents can be
liquid (e.g., melted plastics) and/or more than one phase (e.g., a
2-phase slurry). In addition, the chemical agent preferably does
not have any inherent impurities that detract from the intended use
of the end coke product.
[0418] Various types of plastics can often meet most, if not all,
of the above criteria for the exemplary chemical agents in the
current invention. For example, plastics or chemicals that may be
used in the present invention include, but are not limited to, high
density polyethylene (HDPE), low density polyethylene (LDPE),
polypropylene, polystyrene, polyvinyl chloride (PVC), polyvinyl
acetate, polyacrylonitrile, polyurethane, acrylonitrile butadiene
styrene (ABS), various copolymers, and other plastics and chemicals
having suitable characteristics. In this regard, it should be
recognized that most plastics decompose at the coker operating
conditions and release lighter gases (molecular weight less than
50) as well as more valuable liquid hydrocarbons (C.sub.4+ with
boiling points less than 850.degree. F.). Depending on the specific
plastic compounds, lighter gases would include, but are not limited
to, hydrogen, methane, ethane, propane, ammonia, water, carbon
dioxide, and carbon monoxide. The ability to use mixed plastics in
the current invention provides a major advantage for recycling
plastics. That is, the current barrier to recycling plastics
(separating plastics by type) is effectively overcome. In addition,
readily accessible hydrogen generated from certain plastics can be
effectively used to quench excessive cracking and coking reactions
in the coke mass and the vapor phase of the cracking products. That
is, optimal amounts of hydrogen can be maintained to prevent (1)
`vapor overcracking` (i.e., excessive thermal cracking in the vapor
phase) that yields lower value products, and (2) excessive coking
of the desired `cracked liquids` that yields additional petroleum
coke of lower value (vs. `cracked liquids`). The sources of the
quench hydrogen include, but are not limited to, hydrogen gas,
methane, ethane, propane, ammonia, water, and/or other chemical
agent derivatives that have readily accessible hydrogen atoms. The
quantity and quality of the hydrogen and other light gases
generated from the plastics depends on (1) the types and quantities
of various plastics, and (2) the design and operation of the
petroleum coking process.
[0419] The optimal amount(s) and point(s) of injection for the
chemical agent(s) of the current invention may vary with coker
feedstocks and coker operating conditions. The amount of light
gases (molecular weight <50) and accessible hydrogen generated
by the decomposition of the chemical agent(s) is key to (1)
improved petroleum coke crystalline structure and (2) the desired
quenching of the excessive cracking and coking reactions. The
accessible hydrogen is primarily, but not totally, responsible for
the desirable quenching of excessive cracking and coking reactions.
That is, the other light gases, the coke drum temperature decrease,
and other operational changes of the current invention have quench
effects, as well. While not wanting to be bound by any particular
theory of operability, the quench hydrogen is expected to satisfy
the electron structure sought by the free-radical chemical species,
that are critical to these endothermic, chain reactions.
Eliminating the recurring, free-radical compounds typically stops
or quenches the cracking and coking reactions. Quenching the
excessive coking reactions is one mechanism that disturbs coke
crystal growth; limiting crystal size, increasing coke porosity,
and decreasing coke yields. Thus, vapor overcracking and excessive
coking can be effectively reduced. However, the point of the light
gases' release in the coking process is also important to prevent
premature quenching of the coking and cracking reactions. This
premature quenching of cracking and coking reactions can
essentially defeat the primary purpose of the coking unit: crack
heavy hydrocarbon compounds into more usable and valuable
hydrocarbons referred to as `cracked liquids.` Thus, the optimal
quantity, quality, and point of injection for the chemical agents
of the current invention need to be determined (e.g., pilot plant
studies) for each set of coker feedstocks and associated operating
conditions. In general, the quantity of carbonaceous material(s)
and/or chemical agent(s) may be about 0.5 to about 20 weight
percent, and more preferably about 0.5 to 10 weight percent, of the
feed. Standard engineering principles and practices can be employed
by one skilled in the art to determine the optimal quantity,
quality, and point(s) of injection for the appropriate chemical
agent(s) of the current invention.
[0420] In light of the above considerations, the carbonaceous
material(s) and/or the chemical agent(s) are preferably introduced
into the feedstream in a delayed coking process prior to the coker
heater and/or between the coker heater and the coking drums. For
the same reasons, in a Fluid Coking.TM. process, the carbonaceous
material(s) and/or the chemical agent(s) are preferably introduced
into the feedstream prior to the feed heater and/or between the
coker heater and the burner. As noted, there may be multiple points
of injection. It should also be recognized that some of the
carbonaceous material(s) and/or the chemical agent(s) can be
injected into the feedstream entering the fractionator in a delayed
coking process or entering the reactor in a Fluid Coking.TM.
process depending on the coker feedstock and the coker operating
conditions. Moreover, it should be recognized that the carbonaceous
material(s) and/or the chemical agent(s) can be introduced at other
points in the thermal cracking process depending on the coker
feedstock and the coker operating conditions.
[0421] (4) Current Refinery Operation:
[0422] In some situations, the end-users combustion system is
capable of handling the coke crystalline structure produced by the
coker without additional modifications. For example, process
modifications to achieve the higher VCM coke produce acceptable
levels of shot coke (or coke crystalline structure) without further
process modifications. Alternatively, refineries may have coker
feedstocks (e.g. lighter crude blends) with sufficiently low
asphaltenes and resins, that the production of sponge coke is
already prevalent. In these cases, an increase in coke VCM in the
coking process normally increases the coke porosity. As such, an
increase in coke VCM alone can be sufficient to achieve an upgraded
coke capable of self-combustion.
[0423] (5) General Issues for Control of Coke Crystalline
Structure:
[0424] After the specific levels and types of crystalline structure
required is determined for any given product coke, engineering
factors will determine the optimal use for any of the above
embodiments, separately or in combination. In any combination of
the embodiments, the degree required may be less than specified
here due to the combined effects. Again, these concepts and
embodiments may be applied to delayed coking, Fluid Coking.TM.,
Flexicoking.TM. and other types of coking processes, available now
or in the future.
[0425] C. Decontamination of Petroleum Coke; Additional
Embodiments
[0426] (1) Current Desalting Process with Improved Efficiency:
[0427] The conventional refinery desalting processes, currently in
the refinery, can be modified to achieve the low-level
decontamination required. One or two stage desalter systems can be
improved to >95+% efficiency with sodium levels <5 ppm in the
crude or vacuum distillation feedstock. In some cases, this level
of decontamination can be sufficient.
[0428] (2) Other High-Efficiency Desalting Operations:
[0429] Filtration, catalytic, and other types of hydrocarbon
desalting operations are in various stages of development. The
present invention anticipates the integration of these new types of
desalting operations. These other desalting technologies can
provide sufficient decontamination, if a sodium specification of
<15 ppm (preferably <5 ppm) in the coker feedstock is
achieved.
[0430] (3) Coke Treatment within the Coking Process:
[0431] An additional embodiment for low-level decontamination of
the petroleum coke can include coke treatment in the coking
process. In the decoking cycle of the delayed coking process, the
petroleum coke goes through steam stripping and quenching phases.
During these phases, trace amounts of acid, caustic or other
chemical additives could be added to the water to promote further
reduction of contaminants. In a manner similar to the desalting
process, the "water-washing" of the petroleum coke with steam and
water would remove water-soluble compounds. The decrease in
decoking cycle (created by the reduced drilling time of the softer
coke) could be used for additional residence or treating time, if
appropriate. A closed-loop water system with independent water
treatment may also be desirable for this embodiment. In addition,
the introduction of biological treatment of the petroleum coke can
be included in this embodiment. Overall, this embodiment may be
more desirable than enhanced crude oil desalting systems, due to
the thermal decomposition of the coking process. That is, many of
the complex organic structures containing the contaminants have
been cracked, potentially exposing the contaminants for further
treatment (e.g. reaction and entrainment). The combination of both
embodiments may be very cost-effective. Similarly, the quench phase
(and possibly the stripping phase) of the Fluid Coking.TM. process
can also provide an opportunity for this embodiment of low-level
decontamination.
[0432] (4) Coke Treatment After Coking Process:
[0433] Another embodiment of the present invention can provide
decontamination of the petroleum coke after the coking process is
complete. As noted above, many of the complex organic structures
containing the contaminants have been cracked, in the coking
process, potentially exposing the contaminants for further
treatment. After the degree of required decontamination and the
properties of the upgraded coke are known, normal engineering
skills would be sufficient to develop various engineered solutions
to treat the coke after the coking process. Options for this
embodiment might include various physical, chemical, and/or
biological treatments. Another option may also use the
transportation and storage of the coke to increase treatment time.
This option may require final treatment steps, rinsing, and water
treatment systems at the coke user's facility.
[0434] (5) Coker Feedstock Dilution:
[0435] Another embodiment of the present invention would modify the
coker feedstocks to reduce the concentration of contaminants in the
final coke product. Coke-producing feedstocks with lower
concentrations of the contaminants of concern would be added to the
coker feed to dilute the concentration of contaminants in the
petroleum coke product.
[0436] (6) Coker Feedstock Pretreatment:
[0437] Yet another embodiment of the present invention may include
other types of coker feedstock pretreatment. From a technical
perspective, the addition of a coker feed pretreatment system would
likely be the most effective means of addressing the detrimental
impacts of petroleum coke contaminants. However, this embodiment
often is not economically optimal. The optimal coker feed treatment
system would depend on the composition of the coker feedstocks and
the needs of the petroleum coke user. After the degree of required
decontamination and the impacts of feed treatment decontamination
are known, various engineered solutions would be available to treat
the coker feedstocks. This coker feed treatment system may or may
not include more sophisticated demetallization and/or
desulfurization technologies, described in the prior art. For
example, hydrotreating or hydrodesulfurization of the coker
feedstocks can decrease the sulfur content by 80-95%. If most of
the sulfur is removed from the product coke in this manner, the
excess capacity of in a utility boiler's existing particulate
control device can be used for the collection of other gases (e.g.
carbon dioxide) that are converted to collectible particulates.
Also, desulfurization of the coker feedstock may provide further
advantage by increasing coke VCM and promoting sponge coke.
[0438] (7) Current Refinery Operation with no Further
Decontamination:
[0439] Another embodiment of the present invention may include no
treatment of any kind for decontamination of the coke. As noted
previously, the effects of petroleum coke's high metals content in
combustion and heat transfer equipment is not well understood or
defined. The design and operation of the user's combustion system
plays a major role in determining whether the current level of
contaminants in the coke is acceptable or not. Therefore, some oil
refineries, depending on the coker feedstock blend and coker
operation, may be able to provide the upgraded petroleum coke
without further coke decontamination.
[0440] (8) General Issues for Embodiments of Low-Level
Decontamination:
[0441] After the specific level of required coke decontamination is
determined for any given product coke, engineering will determine
the optimal use for any of the above embodiments, separately or in
combination. The combination of any of these embodiments may reduce
the level of decontamination required by each embodiment,
individually. Finally, these concepts and embodiments may be
applied to other types of coking and desalting processes, available
now or in the future.
[0442] 3. Further Optimization of Delayed Coking Process
[0443] It has been further discovered that the preceding process
modifications may be a subset of process modifications to optimize
coker cracking and coking reactions. This discovery, an enhanced
theory of operation, provides further insight into process
mechanisms and chemical reactions of potential coker process
modifications. As such, the coker process modifications, described
previously, are discussed in a different light for clarification.
In addition, coker process modifications are further discussed.
These additional embodiments of coker process modifications are the
primary focus of this section. However, previous embodiments of
potential coker process modifications should not be limited by this
discovery and its enhanced theory of operation.
[0444] A. Coker Process Modifications: Optimization of Cracking
& Coking Reactions
[0445] This discovery has led to the optimization of coking and
cracking reactions in both the liquid and vapor phases of the
coking process. In the past, the coking process has been viewed as
a complex mass of physical changes and various competing chemical
reactions, primarily coking and cracking reactions. As described
previously, the coking process has two major coking mechanisms:
thermal coking and asphaltic coking. Thermal coking comprises
endothermic chemical reactions: primarily condensation and
polymerization of polycyclic aromatic hydrocarbons (PAHs).
Asphaltic coking is an adiabatic physical change: essentially
desolutation of asphaltenes and resins. The predominant cracking
mechanism is noted to be free-radical, dehydrogenation. This
endothermic, cracking reaction has several process steps. The
initial steps involve the generation of free-radicals that seek
electrons to stabilize their electron configurations and initiate
cracking or the cleavage of chemical bonds, particularly
carbon-to-carbon bonds. The coker operating conditions and chemical
components of the coker feedstocks play major roles in determining
which reactions are more favorable.
[0446] Traditionally, the coker feedstocks are heated to the
highest practical temperature to maximize reactivity and drive the
endothermic cracking and coking reactions to completion. In
general, this approach has been viewed as the most expedient and
efficient manner to achieve the primary objective for traditional
delayed cokers: maximize the extraction of valuable cracked liquids
from the heavy, coker feedstocks. In this manner, many cokers treat
the residual petroleum coke as a by-product with little to no
value. However, excessive cracking and coking reactions in the
liquid and vapor phases can be suboptimal. Consequently, certain
process mechanisms and operating conditions have been developed to
favor desirable reactions over less desirable reactions. In this
manner, the coker reactions are optimized.
[0447] In the liquid phase, the cracking reactions may generally be
preferred over the coking reactions. In traditional coking
processes, cracking the heavy hydrocarbon feedstocks into more
valuable, light hydrocarbons is strongly preferable to any
reactions that produce petroleum coke. However, it has been further
discovered that certain heavy hydrocarbons in the coker feedstocks
can be preferably left with the coke (vs. in the heavy coker gas
oils or coker recycle). That is, a small fraction of the heavy
hydrocarbons that traditionally ends up in the heavy coker gas oil
can offer more value in improving the pet coke quality versus
decreasing the coker gas oil qualities.
[0448] The primary coker feed components of concern are usually
very heavy, polycyclic aromatic hydrocarbons (PAHs) that contain
undesirable sulfur and metals. These heavy, polycyclic aromatic
hydrocarbons are typically vapors in the coke drum between
770.degree. F. and 925.degree. F, usually 800-850.degree. F. In
traditional delayed coking processes, these heavy aromatics are
either recycled to the heater inlet with fresh feed or retained in
the heavy coker gas oil via a deeper cut point. If left in the
coker gas oils, these compounds typically end up as (1)
coke-on-catalyst in the downstream processing units (FCCU,
hydrotreating, etc.), (2) by-products of downstream process(es)
that are recycled as feed to the coker (e.g. FCCU slurry oil),
and/or (3) cracked feed in high severity processing (e.g.
hydrocracking). When cracked, the undesirable sulfur and metals in
these compounds typically end up in the cracked finished products.
Thus, these compounds are undesirable in downstream processing and
are often overvalued by refinery Linear Program (LP) Computer
Models (used to maximize refinery profitability via optimizing
process operating conditions).
[0449] In contrast, these heavy, aromatic compounds can help
increase the coker's propensity for high porosity, sponge coke and
increase coke VCM content. Furthermore, these aromatic compounds
typically contain lower concentrations of sulfur, nitrogen, and
metals .(e.g. vanadium & nickel) than the other coke components
(asphaltenes and resins). Thus, the concentration of these
undesirable elements is also incrementally reduced in the petroleum
coke. In addition, these same heavy, aromatic compounds typically
contain significantly higher concentrations of sulfur, nitrogen,
and metals than other coker gas oils components. Thus, leaving
these heavy aromatics in the pet coke (vs. in the coker gas oils)
can incrementally reduce the concentration of these undesirable
compounds in the coker gas oils. Since the gas oils are further
processed (hydrocracking, FCCU, etc.) to produce transportation
fuels, this may also provide an effective means to further reduce
these contaminants (e.g. sulfur) in transportation fuels (e.g.
diesel), regardless of the improvements in the pet coke qualities
and value.
[0450] In the vapor phase, excessive cracking reactions can produce
suboptimal product yields and cause limits in coker throughput
capacity. In traditional coking processes, cracking reactions
continue to occur in the high temperature vapors coming off the
coke mass, until quenched by steam in the coke drum vapor line
and/or the cold feed in the bottom of the fractionation tower. This
continual cracking of the hydrocarbon vapors can detrimentally
impact coker product yields. That is, this excessive cracking of
hydrocarbon vapors (i.e. "vapor overcracking") converts high-value,
cracked liquids (with 3 or more carbon atoms) to smaller molecules
(primarily methane, ethane, & hydrogen) that can only
practically be used as refinery fuel gas. This refinery fuel gas
often has significantly lower value than the cracked liquid
products. In fact, methane, ethane, and hydrogen typically account
for over 75% of the dried coker gas (Lb-Moles/Hour) from the
fractionation column. In addition, vapor overcracking increases the
vapor loading of the fractionation system. That is, the cracking of
hydrocarbon vapors to smaller compounds creates more molecules of
various hydrocarbon vapors (including cracked liquids) and other
gaseous components. This causes higher vapor flow rates (i.e.
lb.-moles per hour) and pressure drops. Thus, vapor overcracking is
normally undesirable due to (1) lower product yields of valuable
hydrocarbons and (2) the excessive vapor loading of the coker
fractionation system, which can bottleneck or limit the coker
throughput capacity. Alternative coker process modifications have
been developed to reduce undesirable vapor overcracking and further
optimize coking processes.
[0451] (1) Clarification of Patent Objectives:
[0452] In view of this enhanced theory of operation, further
clarification of the patent objectives is provided. As noted above,
some of the patent objectives include (1) modification of the
petroleum coke crystalline structure and (2) increasing the content
of volatile combustion materials (VCMs) in the petroleum coke.
Other patent objectives were also discussed, but clarification of
these patent objectives is helpful in the following discussion
regarding the new discovery.
[0453] Coker Operational Changes: Relative to Current Operation
[0454] Current Operation Assumptions: VCM: 10-12wt. %; Shot or Poor
Sponge Coke
[0455] Examples: Light, Sour Crude; Heavy, Sour Crude
[0456] Modification of the Petroleum Coke Crystalline Structure:
Further definitions
[0457] Sponge Coke: Porous Sponge, Preferable; Dense Sponge, More
Preferable; & Honeycomb, Most Preferable (Technically, But May
Not Be Economically)
[0458] Non-Graphitizable Sponge preferable to Graphitizable Sponge
Coke: Lower C/H Ratio, Increased Reactivity, & Improved Carbon
Adsorption Character
[0459] Thermal vs. Asphaltic Coke: Further Definition of Heavy
Aromatic Compounds
[0460] Increasing Coke VCM Content:
[0461] Types of VCMs: Integration in coke; condensed liquid vs.
adsorption vs. cross-link, vs. condensation bonding (but not fully
integrated; bond broken <1700.degree. F.)
[0462] VCM Added via Coke Quench: Adsorbed in Coke; Higher Quality
VCM
[0463] Thermal Coke Role in VCM content: Non-graphitizable coke;
VCM <1700.degree. F.
[0464] (2) Alternative Perspective of the Exemplary Embodiment:
[0465] Various process options have been discussed that modify
coker operating conditions and/or procedures to achieve the desired
modification of coke crystalline structure and higher coke VCM
levels. However, decreasing the heater outlet temperature was
described as the exemplary coker process modification in many
applications. The lower coking temperature reduces both coking and
cracking reactions, primarily in the liquid phase.
[0466] The types of chemical components in the coker feedstocks
play a major role in determining which cracking and coking
reactions decrease more significantly with the lower coker
operating temperatures. In general, the hierarchy of cracking
reactions usually occurs in the following order (most reactive to
least reactive): paraffins >linear olefins >naphthenes
>cyclic olefins >aromatics. The crackability also tends to
increase with molecular weight (or boiling range). After removal of
side chains, cracking of the very stable aromatic compounds
apparently requires the highest heat of activation. In fact, basic
aromatic ring structures (e.g. benzene) normally require
temperatures higher than normal coker temperatures (or catalysts)
to thermally crack the strong chemical bonds of these compounds.
Thus, the lower molecular weight aromatics will often pass through
the coker without further cracking. Usually, these lighter
aromatics are either (1) cracked in downstream catalytic cracking
processes or (2) become part of the finished product blendstocks
without further cracking. Consequently, cracking of the heavier,
polycyclic aromatics is normally the predominant type of cracking
reaction affected by lower coker operating temperatures (i.e. lower
heat available). As such, the very heavy aromatics will be the
primary feed components that are less likely to crack at lower
coker temperatures. Thus, these feed components tend to remain in
the coke mass due to lower heater outlet temperatures.
[0467] In contrast, the endothermic coking reactions (i.e.
condensation & polymerization) for these heavier aromatics
generally require lower activation energies than their competing
cracking reactions. Otherwise, the cracking of these heavy
aromatics would preferentially occur at lower operating
temperatures, instead of the predominant coking of these aromatics.
Thus, the coking reactions of heavy aromatics are less affected by
the lower heater outlet temperatures (vs. cracking reactions). In
this manner, these heavy aromatics will preferentially coke at
lower coker temperatures, as long as the temperature drops are not
excessive. Thus, heavy aromatics (e.g. PAHS) that are not cracked,
but coked via endothermic reactions (e.g. condensation and
polymerization) and thermal coking. As such, the coking of these
heavy aromatics (i.e. thermal coke) apparently decreases the ratio
(R) of asphaltic to thermal coking sufficiently to form a porous,
sponge coke. Also, heavy aromatics that are not cracked nor coked
can provide low-quality VCMs in the pet coke. In this manner, some
or all of the benefits of the present invention can be achieved by
changing one independent operating variable: decreasing the coker
heater outlet temperature by 5 to 50.degree. F, preferably 5 to
25.degree. F. (most preferably 5-15.degree. F.) with a
corresponding drop in coke drum outlet temperature of 5 to
80.degree. F; preferably 5 to 40.degree. F. That is, the heater
outlet temperature is reduced by 5 to 50.degree. F. from the
traditional coker operation that produces 8-12 wt. % VCM (Volatile
Combustible Materials) for a specific coker feedstock and design,
with other operating control variables held constant. Again, the
reduction in coke drum vapor line temperature is not necessarily
equal to the reduction in heater outlet temperature due to the
changes in the types of endothermic reactions taking place in the
coke drum. The relationship of reduction in heater outlet
temperature, increase in coke VCM, change in coke crystalline
structure, and coke drum vapor line temperature can vary
substantially in significantly different coker feedstocks. Though
this theory of operability can be helpful in understanding the
proper operational changes, the current invention should not be
bound by it.
[0468] Other benefits of decreasing the heater outlet temperature
make it the predominant process modification of the exemplary
embodiment. These potential benefits include, but are not limited
to (1) improving properties of various fuels, (2) reducing fuel
usage/costs, (3) reducing maintenance of heater section, (4)
debottlenecking the coker heater section, and/or (5) improving
overall coker product yields. First, U.S. EPA regulations are
placing further limitations on the sulfur, metals, olefins, and
aromatics contained in the finished fuel products. The lower coker
temperature inhibits formation of olefins and aromatics in
downstream products, while retaining more sulfur and metals of the
heavy aromatics within the coke. This requires less severe
hydrotreating or hydrocracking of coker intermediate product
streams. Secondly, the reduction in heater outlet temperature not
only reduces fuel usage and costs per barrel of unit feed, but can
also reduce the overall fuel usage/costs. Thirdly, one of the
primary sources of coker heater section maintenance is the coking
of the heater tubes & associated tube failures. Lowering the
heater outlet temperature can significantly reduce heater tube
coking and the need for steam injection and periodic decoking
(& associated down time). Fourthly, the reduction in coker
heater outlet temperature and associated reductions in feed recycle
normally reduces limits (debottlenecks) in the heater section and
provides greater operational flexibility and higher heater
capacity. Finally, the overall effect on coker product yields can
provide more favorable coker profitability, in many cases.
[0469] The overall change in coker product yields can vary
significantly among refineries due to (1) design & operation of
various process units, (2) differences in integration of process
units, (3) refinery crude slate, and (4) coker feedstocks. As the
coker feedstocks increase in asphaltene and resin content, greater
quantities of aromatics will generally be required to achieve the
proper asphaltic coking to thermal coking ratio (R) for the desired
porous, sponge coke. With some coker feedstocks, the minor
reduction in heater outlet temperature does not significantly
impact the coker product yields. In these cases, the increased
value of the petroleum coke can more than offset any reductions in
other coker products. For other feedstocks, the required reduction
in heater outlet temperature (e.g. >15.degree. F.) can
detrimentally impact the coker operation and/or product yields
(e.g. substantial loss of other compounds from the heavy coker gas
oil). These coker feedstocks typically have low .degree.API gravity
(e.g. <10) and high Conradson Carbon residue (e.g. >16%). In
many (but not all) cases, this situation may require other coker
process modifications to achieve some or all of the advantages of
the present invention and/or offset detrimental product yields for
economic reasons. The .degree.API gravity is common density
property in the oil industry as determined by the following
formula: .degree.API=(141.5/specific gravity)-131.5. Conradson
Carbon is an indication of the coke residue potential for crude
oils or petroleum derivatives, and is determined experimentally via
ASTM D189-52. Both .degree.API and Conradson Carbon are common oil
industry terminology.
[0470] (3) Additional Embodiments to Achieve Patent Objectives:
[0471] Various coker operational changes have been described that
achieve (1) modified crystalline structure, (2) higher pet coke
VCMs, and/or (3) other advantages of the current invention. These
operational changes were discussed, recognizing that various
combinations of other operational changes were possible. That is,
the present invention is not limited to changes in heater outlet
temperature, but includes other options. The following provides
further detail about potential operating changes with respect to
the heavy aromatics theory of operation. This alternative
perspective also provides clarification of the exemplary
methods.
[0472] The present invention contemplates any coker equipment
and/or process modifications (or any combination thereof) that
selectively encourages the retention of certain heavy hydrocarbons
(primarily polycyclic aromatic hydrocarbons) in the coke mass to
achieve some or all of the objectives such as: (1) modified coke
crystalline structure (porous, sponge coke, preferably with greater
carbon adsorption character) and (2) increased coke VCM content.
The amount of heavy aromatics or other hydrocarbons that remain in
the coke mass are primarily dependent on the local operating
conditions; the coke drum, in particular. The primary local
operating conditions that selectively retain the heavier aromatic
hydrocarbons include: lower coke drum temperature, higher coke drum
pressure, reduced cycle times, coker feed modifications, change in
coker recycle rate, and potential catalyst additives. The
selectivity of any process modifications can vary from refinery to
refinery due to variability in coker design, operation, and
feedstocks. The degree of selectivity for each coker equipment
and/or process modifications can also vary and does not require
high selectivity (e.g. >80%) to be sufficiently effective.
[0473] Various operational controls can be modified to achieve the
desired retention of coker feed components in the coke mass and the
other advantages of the present invention. The four primary
independent control variables for the traditional delayed coker
operation are (1) heater outlet temperature, (2) fractionator
pressure, (3) fractionator hat temperature, and (4) residual carbon
in the coker feedstocks. Other operational variables are directly
or indirectly affected by (or dependent upon) changes in these
control variables. For example, the amount of heavy aromatics or
other hydrocarbons that remain in the coke mass are dependent on
the local coke drum temperatures. As noted above, the heater outlet
temperature indirectly affects the coke drum temperature, depending
on the remaining degree of endothermic cracking and coking
reactions. Increasing fractionator pressure is an alternative
control that can increase coke drum pressure to achieve some or all
of the advantages of the present invention. For given coker
feedstocks, the fractionator hat temperature has a limited impact
on the amount of heavy hydrocarbons left in the coke mass. That is,
heavy aromatics leaving the coke drum go to either heavy gas oil or
recycle, depending on fractionator hat temperature. Finally, as
noted above, altering the coker feedstocks can also be used to
achieve some or all of the advantages of the present invention.
[0474] a. Coke Drum Temperature:
[0475] In the prior art, coke drum temperature (measured unquenched
in overhead vapor line) is typically maintained at temperatures of
>820.degree. F. (preferably 830-870.degree. F.) to achieve coke
VCM content <12 wt. %. The current trend is to maximize coke
drum temperature to heater and/or coke hardness limits. In
contrast, the coke drum temperature can be reduced from current
operation by 5-80.degree. F. (preferably 5-40.degree. F. ) to
achieve some or all of the advantages of the present invention by
(1) reducing undesirable cracking and/or coking reactions and/or
(2) condensing heavier hydrocarbons to remain in the coke drum
until cracked or coked. That is, drum outlet temperatures of the
current invention can range from 750 to 865.degree. F. (preferably
770 to 825.degree. F.). More importantly, however, for a particular
coker and coker feed blend, the coke drum temperature is reduced by
5-80.degree. F. (preferably 5-40.degree. F.) from coke drum
temperatures that achieve coke VCM content <12 wt. %. Reducing
the heater outlet temperature can do either or both. Alternatively,
chemically quenching the endothermic cracking and/or coking
reactions can achieve the former. On the other hand, a thermal
quench within the coke drum can have a net effect of doing either
or both, as well. Finally, other methods that effect coke drum
temperature (e.g. reduced insulation) can also produce some desired
effects.
[0476] a1. Heater Outlet Temperature:
[0477] As discussed previously, the reduction of the heater outlet
temperature may be the desired operational change to achieve some
or all of the advantages of the present invention. In many coker
operations, a modest reduction in heater outlet temperature of
5-50.degree. F. (preferably 5-25.degree. F.) can be sufficient to
achieve the desired coke drum temperature, its associated increase
in VCM and the additional thermal coking required to produce a
highly porous, sponge coke. However, in other coker applications,
the reduction in heater outlet temperature required to achieve
these benefits can be excessive. That is, technical and economic
limitations in certain applications can be prohibitive in the sole
use of reduced heater outlet temperature to achieve the advantages
of the present invention. These limitations can include, but are
not limited to, (1) excessive drop in cracking (e.g. napthene rings
are difficult to crack at temperatures <900.degree. F.), (2)
insufficient heat available for coking reactions (e.g. significant
pitch-like material vs. coke), and/or (3) significant detrimental
impacts on yields of cracked liquids and associated profitability
losses. In these situations, other coker process changes of this
invention can be used in lieu of or in combination with a less
severe reduction of heater outlet temperature.
[0478] a2. Coke Drum Chemical Quench:
[0479] The benefits of injecting certain carbonaceous materials
into the coker feedstock were briefly described earlier. When
cracked, these carbonaceous materials generate low molecular weight
compounds (e.g. carbon monoxide) that can alter the cracking and
coking reactions in a manner that inhibits shot coke formation
(i.e. encourages sponge coke). For example, certain plastics can
produce free radical hydrogen that can potentially terminate
cracking mechanisms downstream of the primary reaction zone and
inhibit vapor overcracking. These free radicals can also assist in
thermal coking mechanisms. Apparently, this chemical quench of the
cracking reactions and the increased thermal coking reactivity can
improve coke crystalline structure and potentially increase coke
VCM. This type of chemical quench can be effectively added to the
coker feed at rates of (0.1 to 20 wt. % of feed; preferably 0.1 to
8.0 wt. % of feed). In a similar manner, hydrogen can be injected
downstream of the primary reaction zone with similar results. This
other embodiment is discussed in more detail in the section on
vapor overcracking.
[0480] a3. Coke Drum Thermal Quench:
[0481] A thermal quench of 5-80.degree. F. (preferably 5-40.degree.
F.) near the vapor exit of the coke drum (vs. vapor line quench)
can be a desired method in some cases to achieve some or all of the
benefits of the present invention. The primary intent of this
thermal quench within the coke drum is an effective condensing of
the heaviest vapors back into the coke drum. These heaviest vapors
are typically heavy aromatics (e.g. PAHs) that undergo further
coking or cracking with additional residence time in the coke drum,
particularly at the end of the coking cycle. The selective
condensation of the heaviest vapors (vs. lighter recycle vapors or
heaviest heavy coker gas oil--HCGO components) can selectively
promote some or all of the benefits of the present invention with
the vapors of lowest value. Various quench media can be used, but
cooled heavy coker gas oil (e.g. product or fractionator
pump-around reflux system) may be suggested to mitigate vapor
loading problems in the fractionator section. In this manner, a
thermal quench can also be used to achieve some or all of the
advantages of the present invention. Reduction of vapor
overcracking may be an added benefit or additional intent for this
thermal quench of vapors.
[0482] The quench media can be introduced into the coke drum via
various mechanical devices. In some cases, the existing anti-foam
injection system(s) can be modified to serve both purposes:
antifoam and coke drum thermal quench. Existing anti-foam injection
systems typically use a gas-oil carrier to convey a silicone
antifoam, but are often positioned as far from the exit vapor line
as possible to avoid silicone carryover. The existing anti-foam
system could be modified to increase the gas oil flow rate and/or
add other quench media to achieve the desired coke drum
temperature. Other quench media can include, but may be limited to,
coker gas oils, various fuel oils, and other chemical compounds
that have desirable characteristics, but limited impacts on the
coker drum and fractionator systems. Alternatively, additional or
separate injection lances (1 to 8; preferably 1 to 4) can be
mounted near the coke drum vapor exit(s). Examples of injection
lances through bolted flanges are shown in FIGS. 6A-6D. The quench
media injection lances 610a, 610c penetrate the coke drum 620a,
620c via reinforced flanges 630a, 630c. The reinforced flanges can
be welded to the top of the coke drum, following proper ASME
procedures to maintain pressure integrity. Likewise, the lances may
be properly welded in the flange cover plates. The materials of
construction for both injection lances and mounting flanges are
sufficient to perform their functions in the coke drum operating
environment. The angle of the flange mountings, the lance
mountings, and lance spray nozzles may be designed to sufficiently
cover the vapor disengagement zone of outage areas in each coke
drum. That is, the quench media spray(s) of the lances preferably
cover the entire vapor flow before exiting the coke drum via coke
drum vapor line(s) 640a, 640c. Furthermore, the injection lances
may not extend into the coke drum more than a predetermined
distance, e.g., about 10-15 feet in a typical embodiment, to
mitigate potential pluggage with coke. Also, the design preferably
allows replacement with spare lance(s) during the decoking cycle
should loss of flow occur. Other potential embodiments of the
coking vapor quench are shown in FIGS. 6E to 6H. In these
embodiments, the vapor quench occurs external to the coke drum
620e, 620g in the overhead vapor line 640e, 640g via injection
lances 610e, 610g. These embodiments can use the force of gravity
to convey to the condensed, heavy hydrocarbons back into the coke
drum. However, these quench systems may not be preferred in many
cases, due to their potential build-up in the vapor line, causing
flow restrictions and/or undesirable pressure drops. Ones skilled
in the art can develop other mechanical devices that would achieve
effective thermal quench of vapors prior to exiting the coke drum
and accomplish some or all of the process advantages of the present
invention. The required flow rates of the chosen quench media can
be readily determined by one skilled in the art via standard
engineering procedures and heat balance calculation methods.
[0483] a4. Reduced Coke Drum Insulation:
[0484] Reducing the degree of coke drum insulation can be used, to
a certain degree, to reduce coke drum temperature. In particular,
less insulation in the upper portion of the coke drums can
contribute to the reduction in coke drum outlet temperature (i.e.
unquenched vapor line temperature) without thermally quenching
primary cracking and coking reactions in the lower drum. This
option can contribute to the condensation of the heaviest vapor
components (e.g. heavy aromatics) leaving the drum and help reduce
vapor overcracking. However, this option can also cause localized
phenomena with a more pronounced temperature gradient near the coke
drum shell. This can cause undesirable variability (e.g. less
control) in the cracking reactions and coke crystalline
structure.
[0485] b. Coke Drum Pressure:
[0486] In the prior art, the coke drum pressure is typically
maintained between 15-30 psig. The current trend is to minimize
coke drum pressure to reduce coke yield within the operational
limits. In contrast, increasing the coke drum pressure by 3-30 psig
(preferably 3-10 psig) is an effective method to condense the
heaviest components (e.g. PAHs ) of the vapors leaving the coke
drum. That is, coke drum pressures of the current invention can
range from 15-40 psig (preferably 20 to 30 psig). More importantly,
however, for a particular coker and coker feed blend, the coke drum
pressure is increased by 3-30 psig (preferably 3-10 psig) from coke
drum pressures that achieve coke VCM content <12 wt. %. The
simplest and most common method for increasing coke drum pressure
is to increase the fractionator pressure by increasing backpressure
at the wet gas compressor. However, capacity and other limitations
can make other creative approaches to increase coke drum pressure
more desirable, including various mechanisms to control and balance
system pressures.
[0487] b1. Fractionator Pressure:
[0488] Increasing the coker fractionator pressure usually increases
the coke drum pressure. The higher drum pressure suppresses the
vaporization of heavier components remaining after cracking and
coking of coker feed or recycle. As such, less quantity of the
high-boiling hydrocarbons, including heavy aromatics (e.g. PAHs),
are transferred from the coke drum to the coke drum vapors and the
coker fractionation column. In this manner, increasing the
fractionator pressure generally leaves more of the heavier
aromatics in the coke mass within the coke drum. Thus, increasing
the coke drum pressure (via controlling the fractionator pressure)
is an acceptable process modification to achieve the benefits of
(1) modified coke crystalline structure and (2) increased coke
VCMs. In some cases, this process modification may be preferred due
to its simplicity. However, this alternative can cause compressor
overloading, associated capacity limits, and/or some detriment to
product yields. In some cases, other means could be logically
employed to increase drum pressure with limited impact on the
existing compressor system.
[0489] b2. Alternative Mechanisms to Increase Coke Drum
Pressure:
[0490] As noted above, creative alternative approaches can be used
to increase control and/or balance system pressures to increase
coke drum pressure. For example, the pressure drop between the coke
drum and fractionator could be mechanically increased and
controlled. By increasing heater outlet pressure (e.g. heater inlet
pump(s) and/or injection steam pressure), coke drum pressure can be
increased, to a certain extent, with less impact on the pressures
of the fractionator and downstream equipment. A variety of
mechanisms could be used for increasing and controlling pressure
drop between the coke drum and fractionator. The partial coking of
vapor lines already increases the pressure drop between coke drum
and fractionator by as much as 8-10 psig. In a similar manner, a
smooth transition orifice spool could be designed for insertion in
the vapor line downstream of the quench zone. This static pressure
drop control would change with vapor flow (i.e. velocity).
Alternatively, a variable throat venturi, similar to those used in
wet scrubber applications, could be developed to achieve better
pressure drop control. However, potential pluggage or other
problems are more likely with this type of device. One skilled in
the art can develop a suitable solution that addresses the
particular needs (risks vs. benefits) of the specific coker
application.
[0491] c. Reduction in Cycle Time:
[0492] In the prior art, coking cycle times typically range from
16-24 hours. The current trend is to minimize cycle times within
equipment, operational, and coke quality (e.g. <12 wt. % VCM)
constraints. In contrast, reducing coking cycle time by 2-12 hours
(preferably 4-8 hours) can be effective in increasing coke VCM and
potentially produce desirable modifications in coke crystalline
structure. That is, coking cycle times of the current invention can
range from 12 to 24 hours (preferably 12 to 16 hours). More
importantly, however, for a particular coker and coker feed blend,
the coker cycle time is reduced by 2 to 12 hours (preferably 4-8
hours) from coking cycle times that achieve coke VCM content <12
wt. %. Lower cycle times reduce the residence time of the cracking
and coking reactions. As a result, the VCM content of the coke
increases by approximately 1 wt. % for each 4-6 hours reduction in
cycle time. Furthermore, an increase in thermal coke production can
occur in coker operations, where the reduction in cycle time has
more pronounced effect on cracking versus coking reactions. That
is, the coking of heavy aromatics (e.g. PAHS) is more favorable
than their respective cracking reactions. In this manner, a
reduction in coking cycle time can be effective in achieving some
or all of the benefits of the present invention such as: increased
coke VCM and modified crystalline structure (porous sponge
coke).
[0493] d. Feed Modifications: In the prior art, the coker feeds
have gotten progressively worse. Heavier crudes have typically
pushed delayed cokers to coking limits (e.g. coker & refinery
bottlenecks). Consequently, the current trend is to minimize coker
feeds of higher quality (e.g. reducing virgin gas oil content or
increasing end points on virgin & heavy coker gas oils),
increasing Conradson carbon of coker feeds >22. In contrast,
various modifications to the coker feed (Conradson carbon <26;
preferably <20) can be used as additional methods for achieving
some or all of the advantages of the present invention. These
modifications can take the form of modified crudes slates, coker
feed blends, and/or coker feed additives. Modifications of the
coker feed can integrate more aromatics (Aromatics with propensity
to coke >40 wt. % of coke; preferably >60 wt. % of coke) in
the coke mass. That is, the addition of coker feedstocks with
higher aromatic contents will generally increase thermal coking and
decrease the asphaltic coking to thermal coking ratio (R) in the
coke drum. This increased thermal coking (endothermic) can also
have a significant impact on the coke drum temperature. In this
manner, coker feed modifications can produce the desired
crystalline structure and potentially increase coke VCM content via
heavy hydrocarbons not fully integrated in the coke. Coking limits
can be mitigated by operational benefits of the current invention
(e.g. decreased cycle times). The degree of feeds blend
modification can readily be determined by one skilled in the art
for a specific refinery/coker application, based on coker design
(and coking limits), available coker feeds, relative impact on
Conradson Carbon, and overall impact on coke quality.
[0494] d1. Modified Coker Feed Blends and Crude Slates:
[0495] The current coker feed blend can be composed of different
proportions of the same feedstocks to produce a blend with higher
concentration of heavy aromatics. Alternatively, the current coker
feed blend could be blended with other coker feedstocks (e.g. 1-50
wt. % of the total blend; preferably 3-10 wt. %) to produce a
desired coke feed blend. These coker feedstocks would include, but
should not be limited to, aromatic crude oils, thermal tars, coal
tars, pyrolysis tars, coal tar pitch, heavy virgin gas oil (HVGO),
furfural extracts, phenol extracts, and slurry oils (e.g. decanted
oil from the FCCU). Other intermediate product, byproduct, or waste
streams that contain a significant portion of aromatic compounds
(e.g. >30 wt. %; preferably >50 wt. %) could also be used as
coker feed blendstocks. In this manner, modification to the coker
feedstocks can be an effective means to partially or fully achieve
the benefits of the present invention. The same objective could
also be achieved by increasing higher quality crudes in the crude
blend: lighter, paraffinic, and/or aromatic. In addition, the heavy
virgin gas oil (HVGO) can be added directly to the coker feed.
However, lowering the cut point in the vacuum tower and leaving
only the heaviest HVGO in the vacuum resid (i.e. coker feed) would
be preferable. This vacuum distillation change has the added
benefit of incrementally improving FCCU feed quality of the
HVGO.
[0496] d2. Coker Feed Additives:
[0497] As noted previously, certain carbonaceous compounds can be
added to the coker feed to enhance the ability to achieve some or
all of the advantages of the present invention. The breakdown of
these carbonaceous materials apparently produces intermediate
compounds that inhibit shot coke formation and favor thermal
coking. These carbonaceous additives include, but should not be
limited to, coal wastes, wood wastes, cardboard, paper, plastics,
and rubber. These solid carbonaceous materials may be finely
pulverized (>80 wt. % <100 mesh) and may, for example, be
added to the coker heater feed via methods described in expired
U.S. Patent 4,096,097. Additional details, particularly for
plastics and rubber, are provided later. (See Plastic/Rubber
Addition to the Delayed Coker: Exemplary Embodiment).
[0498] e. Coker Recycle Rate:
[0499] In prior art, coker recycle rates are typically maintained
at 10-35 wt. %. The current trend is to minimize coker recycle
within operational constraints (e.g. coke drum heat balance) to
minimize coke yield. In contrast, modifying coker recycle rates can
be effective in promoting thermal coke reactions and potentially
increasing coke VCM. In the prior art, decreasing the coker recycle
rate has been used to decrease coke yield by increasing the heavy
components of the coke drum vapors drawn into the heavy coker gas
oil. Conversely, increasing the recycle rate leaves these heavier
components of the HCGO (e.g. heavy aromatics) in the recycle stream
and increases yields of thermal coke. Alternatively, other
operational methods of the current invention can preferably leave
these heavier vapor components in the coke drum and reduce coker
recycle rate. The resulting lower recycle rates can often provide
sufficient heater and coke drum capacity to add coker feeds with
significant aromatic content, which tend to increase thermal coke.
Consequently, these three methods of modifying coker recycle rates
may be used to achieve some or all of the benefits of the present
invention.
[0500] e1. Feed Alternatives with Reduced Coker Recycle Rate:
[0501] In the prior art, the coker recycle rate has often been
reduced to decrease coke yield for a given feed. by increasing the
fractionator hat temperature. The fractionator hat temperature is
the temperature of the vapors rising to the gas oil drawoff tray in
the fractionator. Increasing the hat temperature increases the gas
oil end point, the upper end of its boiling range. This increases
amounts of higher boiling components (e.g. 900.degree. F. to
925.degree. F.) in the heavy coker gas oil. The incorporation of
these higher boiling point components into the heavy coker gas oil
(HCGO) lowers the coker recycle rate. This reduction of coker
recycle rate is limited by (1) acceptability of heavier HCGO
components in downstream processing and (2) heat requirements of
the coke drum to complete desirable cracking and coking reactions.
In the latter, the additional heat carried by the heated recycle
stream into the coke drum is often critical to provide sufficient
heat for cracking and coking reactions. A heat balance around the
coke drum reveals:
Q.sub.in=(FF+R).times.avg.
Cp.times.T.sub.in=Q.sub.out+Q.sub.cracking+Q.su-
b.coking+Q.sub.walls+Q.sub.quench
[0502] Where Q=associated heat values; FF=fresh feed; R=coker
recycle rate; avg. Cp=average combined feed (i.e. FF+R) heat
capacity at Tin; and Tin=coke drum inlet temperature. This
simplified formula shows that significant reductions in coker
recycle rates can have substantial effects on the heat available
for cracking and coking reactions, if the heater outlet temperature
remains constant. Thus, increases in heater outlet temperature are
often implemented to offset any reductions coker recycle rate.
Consequently, heater limitations and the feed's propensity to coke
typically limit reductions in coker recycle rate in the prior art.
However, reductions in coker recycle rate generally makes more
heater feed capacity available. This feed capacity can be used for
increased feed rate, if available. Alternatively, various coker
feed alternatives (advocated earlier) can be added to the current
feed to potentially increase thermal coke and coke VCM. Either or
both of these alternatives can significantly increase the heat
available in the coke drum and offset the loss of recycle rate.
That is, even with lower heat capacities than the traditional
recycle materials, these coker feed alternatives (e.g. plastics,
rubber, etc.) can provide sufficient heat in many cases. Also,
these coker feed alternatives often have less coking propensity and
require less heat to be cracked to valuable cracked liquid
products.
[0503] e2. Increased Coker Recycle Rate:
[0504] Conversely, increasing the coker recycle rate by 3-30 wt. %
(preferably 3-15 wt. %) can achieve some or all of the advantages
of the present invention by increasing heavy aromatics and thermal
coking in the coke mass. That is, coking recycle rates of the
current invention can range from 5 to 50 wt. % (preferably 15 to 35
wt. %). More importantly, however, for a particular coker and coker
feed blend, the coker recycle rate is increased by 3-30 wt. %
(preferably 3-15 wt. %) from coker recycle rates that achieve coke
VCM content <12 wt. %. Decreasing the fractionator hat
temperature leaves the heavier components of the HCGO (e.g. PAHs)
in the fractionator bottoms that are recycled with fresh feed to
the coker heater. As such, decreasing the hat temperature increases
the coker recycle rate. In this manner, the coker recycle goes
through the heater and coke drums until it is either (1) converted
to lower boiling range components that leave with the heavy coker
gas oil (or other cracked products) or (2) integrated into the coke
mass. Since this additional recycle tends to be primarily heavy
aromatics, the increased coker recycle rate tends to increase
thermal coking and potentially increase coke VCM, depending on the
level of coke carbonization. In addition, the reductions of these
heavier components in the HCGO make it a higher quality feed for
downstream processing (e.g. FCCU). Increases in coker recycle rates
of this manner are limited by heater capacity, coke drum capacity,
and/or recycle stream's propensity to coke.
[0505] e3. Optimal Recycle Rate and HCGO Quality:
[0506] Another process option may achieve some or all of the
benefits of the present invention while decreasing coker recycle
rate and improving HCGO quality. Other operational methods,
previously advocated in the current invention via (e.g. lower drum
temperature or higher coke drum pressure), can condense the
heaviest components in the coke drum prior to reaching the
fractionator. Thus, these heaviest components do not end up in
either of the HCGO (higher quality) or the recycle stream (lower
recycle rate). Again, it should be noted that these heaviest
components of the coke drum vapors are significantly heavier than
the heaviest components of the HCGO, as determined by the
fractionator hat temperature. Thus, the limits of decreasing coker
recycle rate are similar to decreasing coker recycle in the prior
art: heat balance limitations. However, in this method of the
current invention, there is greater operational flexibility: (1)
lower recycle rates without lower HCGO quality (i.e. due to higher
hat temperature), (2) higher HCGO quality (i.e. due to lower hat
temperature) with constant recycle rates, or (3) other combinations
of HCGO quality and recycle rates. Preferably, the condensation of
the heaviest recycle components (e.g. PAHs) in the coke drum allows
a decrease in hat temperature (3-40.degree. F.; preferably 5 to
20.degree. F.) to increase HCGO quality, while still reducing the
recycle quantity with improved quality (e.g. less heater coking
propensity). This reduced recycle rate provides (1) reduced heater
severity (e.g. less fuel & less heater tube coking), (2)
availability of more heater feed capacity and/or (3) various coker
feed alternatives (advocated earlier) can be added without
exceeding heater limits. In this manner, some or all of the
benefits of the present invention can be achieved via a modest
reduction in the heaviest components of the heavy coker gas oil. In
addition, the coker recycle rate can be reduced while maintaining
proper coke drum heat balance and improving HCGO quality. One
skilled in the art can achieve optimal (1) condensation of heaviest
recycle components, (2) HCGO quality, (3) recycle rate, and/or (4)
feed additives via empirical studies (e.g. pilot plant) for
specific coker design, feed blends, and operating objectives (e.g.
LP Model). The primary operating variables would include (1)
quenched coke drum temperature, (2) coke drum pressure, and (3) hat
temperature.
[0507] f Catalytic Additives:
[0508] Finally, catalytic compounds can be added to the coker feed
and/or the coke drum downstream of the primary reaction zone to
enhance thermal coking reactions. These catalysts will allow the
endothermic thermal coking reactions to take place with lower heat
of activation and often at lower temperatures. Consequently, these
thermal coking (condensation and polymerization) reactions can
preferentially proceed versus endothermic cracking reactions that
compete for available heat at a given drum temperature. For
example,
[0509] As noted above, various coker process modifications can be
employed as alternatives to achieve some or all of the advantages
of the present invention such as: (1) modified coke crystalline
structure with greater carbon adsorption character and (2)
increased coke VCM content. That is, lower coke drum temperature
(via heater outlet temperature, and/or drum thermal quench), higher
coke drum pressure (via fractionator pressure, feed pressure,
controlled pressure drops, and/or other mechanism), coker feed
modifications (via crude slate, coker feedstocks, and/or various
feed additives), recycle rate (via hat temperature or reductions in
heavy aromatic compounds left on coke vs. in recycle), and/or
catalyst additives can effect the desired retention of certain
hydrocarbons in the pet coke. Though each will work to a limited
degree, their effectiveness will vary from refinery to refinery. As
a result, any combination of these alternatives can be used to
effectively achieve some or all of the advantages of the present
invention. However, their effects may not necessarily be additive.
In certain situations, the optimal value(s) of the operating
variables may lie outside the ranges specified above due to the
combined effects or anomalies of an atypical coker system. Thus,
standard engineering principles and practices of those skilled in
the art (including pilot plant studies) may be necessary to
determine the optimal combination and their application for each
refinery system.
[0510] In each specific coker application, one skilled in the art
can achieve some or all of the invention benefits through the use
of any one or combination of the process options described herein.
The optimal combinations and degree of utilization of these process
options can be determined by applying engineering principles &
practices with this information and the proper characteristics of
the coker design, operation (including history and objectives), and
available coker feeds. Modest testing (e.g. laboratory and/or pilot
plant) may be necessary to determine certain characteristics and
operating effects for particular coker feeds. This is consistent
with typical refinery practice for evaluating any significant
change for coker operations.
[0511] B. Novel Process Modifications to Reduce Vapor
Overcrackinq
[0512] (1) Quench Cracking Reaction in Vapor:
[0513] Various means to quench the cracking reactions of the
delayed coking process were briefly described earlier. One such
mechanism was the introduction of certain plastics that released
hydrogen, when cracked. The purpose of the following section is to
describe other mechanisms that accomplish the same objective. The
introduction of chemical agents that release hydrogen or other
free-radical species (e.g. low-molecular weight) can terminate
cracking reactions by satisfying the electron structure of
intermediate free-radical species that are active in the cracking
reaction mechanism due to their instability. Hydrogen may be the
preferred free-radical because it may be more likely to terminate
the reaction mechanism rather than initiate some additional
cracking. These chemical agents should not be limited to plastics,
and include rubber compounds, ammonium compounds, etc. These
compounds tend to release hydrogen due to cracking of the chemical
agent at the operating conditions of the coking process. The
release of hydrogen in the primary cracking zone can prematurely
terminate liquids cracking and be very detrimental to the primary
objective of the coking process. Thus, the hydrogen is ideally
released downstream of the primary cracking zone. Consequently, the
primary mechanisms, presented here, inject chemical agents directly
into the vapor phase above the surface of the semi-solid coke mass.
There are various methods to introduce these chemical agents, but
the an exemplary method would use a modified drill stem system. In
addition, an exemplary embodiment for this vapor overcracking
quench will be discussed in the following sections.
[0514] a. Chemical Quench:
[0515] The injection of chemical agents to satisfy the electron
structure of the reactive, intermediate free-radicals (e.g. chain
reactions) is an effective way to stop the cracking reactions in
the vapor phase. Chemical agents that serve this purpose would
include hydrogen, acids, and other chemicals that act as electron
donors or can be easily converted to free-radicals. Similar to
plastics (discussed earlier), other chemical agents can be injected
with the feed that release hydrogen (thermally or otherwise)
downstream of the primary cracking zone. In this manner, the
chemical agents indirectly provide hydrogen to satisfy the electron
structure of the free radical(s). That is, these chemical agents
effectively react with intermediate free-radicals and make them
substantially less reactive. As a result, the cracking mechanism is
terminated or quenched. Likewise, other chemical agents can release
free radicals (other than hydrogen), which react with the vapor
compounds to terminate or quench vapor overcracking. Similarly,
these and other chemical agents can be added downstream of the
primary cracking zone. These chemical agents either react directly
or via an intermediate (e.g. free radical) to quench free-radicals
and terminate cracking, preferably in the vapor phase.
[0516] b. Thermal Quench:
[0517] The injection of various quench media can also be effective
in reducing the vapor temperature and quenching the cracking
reactions in the vapor phase. Quench media can include, but should
not be limited to, water, steam, and liquid hydrocarbons
(preferably with high boiling range and high heat of vaporization).
The degree of quench media addition is typically determined by the
desired cooling of vapors from 5 to 80 degrees Fahrenheit,
preferably 5 to 40 degrees Fahrenheit. This level of cooling may be
sufficient to thermally quench excessive vapor cracking reactions,
as well as condense heavy hydrocarbon vapors that would otherwise
exit the coke drum. Water may be preferred over steam to minimize
water required (i.e. water vapor in the exiting process gas stream)
via the cooling effect of the heat of vaporization of water.
However, at high coke drum temperatures, careful design of the
injection method may be required to avoid premature vaporization of
the water (or other liquids) and expansion or pressure problems.
Alternatively, high molecular weight, liquid hydrocarbons (e.g.
coker gas oils) may be the preferred cooling medium due to their
high heat of vaporization per pound mole and their tendency to
remain a liquid at coke drum temperatures with higher pressures
prior to injection into the coke drums. This temperature quench can
have the added benefit of reducing the heavy hydrocarbon vapors
(preferably aromatics) that are preferably kept in the coke mass
(discussed previously in section: Coke Drum Thermal Quench). That
is, these heavy aromatic vapors exiting the coke drum can be
condensed in a manner similar to an increase in drum pressure or
the thermal quench systems exemplified by FIGS. 6A-6H.
[0518] c. Injection Method:
[0519] The injection of these chemical agents into the vapor phase
of the coking cycle (vs. decoking cycle) in the coke drum can be
accomplished by various methods. Ideally, this coke drum quench in
the coking cycle would occur at the interface of the coke-foam and
the product vapors. From a practical standpoint, the injection of
the quench may have to occur in various levels of the coke drum
with the means to clean the injection ports on a regular basis
without coker unit shutdown. As a minimum, quench injection at the
top of the coke drum in the outage area would be needed. This
option was discussed in the Coke Drum Thermal Quench section, noted
above (e.g. FIGS. 6A-6H). Conceivably, even the injection of quench
media with the coker feed at the base of the coke drum would quench
the coker and cracking reactions similar to a reduction in feed
heater temperature. However, this injection method would quench
cracking and coking reactions in both the liquid and vapor phases.
This would be similar to visbreaking technology and can
substantially change the coker product yield distribution.
[0520] Certain injection methods (e.g. minimum & preferred) can
have beneficial side effects. Injection into the foam layer on top
of the coke mass may also act as anti-foaming agents. That is, the
injection of high-pressure hydrogen, gas oils, and/or steam can
disperse bubbles via turbulence breaking liquid surface tension.
Conceivably, additional anti-foaming agents could also be injected
with the thermal and/or chemical quench media to achieve even less
foam.
[0521] An exemplary method of injection would use a modification of
the existing drill stem, which is currently used for hydraulically
cutting the coke in the decoking cycle. A totally separate,
modified drill stem would be most preferable. The drill stem design
would be modified to allow injection of the chosen quench media
(chemical and/or thermal). Depending on the media, drill stem
modifications can include, but should not be limited to:
[0522] Design: Size & mechanics determined by media type (e.g.
phase) and flow requirements
[0523] Spray Nozzle Design: Size & angle(s) determined by spray
pattern to cover desired area
[0524] Materials of Construction: Withstand coking cycle operating
conditions;
[0525] temperature, pressure, etc. (e.g. length limited due to
torsional stresses in high operating temperatures)
[0526] Improvements in materials technologies (e.g. composites) can
optimize design
[0527] Drill Stem Cooling System: cooling media passing through
drill stem to dissipate excess heat
[0528] For example, steam/N.sub.2 flowing in annulus of
concentric-pipe drill stem (e.g. split-ring)
[0529] This modified drill stem design can require advanced drill
stem metallurgy to withstand operating conditions of the coking
cycle. Also, the modified drill stem would require a special
sealing apparatus to prevent leakage at the interface with the
upper drum head at high pressures. Fortunately, the weight of the
drill stem will counter the upward force of the pressure in the
coke drum, and require lower forces to maneuver it vertically.
Modern sensing technology and/or computer simulations, based on
process inputs, can accurately control the distance between the
drill stem and the top of the semi-liquid coke mass. As technology
progresses in these areas (e.g. composite materials science,
sealing, and coke level sensing technologies), the use of a
modified drill stem will become increasingly advantageous.
[0530] The modified drill stem is employed by a system that is
similar to the current decoking system. First, the modified drill
stem would be maneuvered through its functions using the coke drum
derrick. That is, the modified drill stem can be connected,
lowered, raised, and rotated using similar mechanisms employed by
the existing decoking drill stem system. Preferably, the modified
drill stem does not require rotational motion to avoid undesirable,
torsional stresses. The major difference, in this regard, will be
the addition of the sealing mechanism with bolted flange cover.
Secondly, modified drill stem connections to the media supply
system (e.g. pump) would be similar to decoking drill stem
connections to high-pressure water system.
[0531] An example of the modified drill stem system for a coke drum
with a side draw vapor line is shown in FIGS. 7A-7B. In this
equipment diagram, the modified drill stem 710 passes through a
sealing apparatus 715 mounted on the cover of a reinforced flange
720 in the center of the coke drum. Normally, this may be the same
flange used for the existing drill stem to drill out the coke in
the decoking cycle. At the end of the decoking cycle, the existing
coke drum derrick 740 is typically used to position the modified
drill stem. Initially, the modified drill stem is normally
retracted with sealing apparatus 715 welded to flange plate near
the spray nozzle end. After the flange is properly bolted and the
drum is pressure checked, the modified drill stem is lowered into
the drum to its maximum extension. During this descent in the drum,
the modified drill stem can be designed to provide additional
benefit of moderating coke drum warm-up (e.g. steam injection). As
the coking cycle begins, pressurized quench media is injected into
the coke drum above the coke mass via spray nozzle(s) 750. An
automated control system, designed for each specific coker, would
be used to assure that the modified drill stem would be moved
vertically upward (i.e. retracted) at a rate that maintains at
least a minimum distance (e.g., 2-20 feet; preferably 5-10 feet)
above the coke mass, as the coke drum fills. This minimum distance
can depend on the anti-foaming effect of the quench media. As noted
previously, certain chemical additives in the quench media can
increase the anti-foaming effect. The automated control system
would preferably have fail-safe design modes and operational
procedures to assure the modified drill stem does not get stuck.
The high-pressure nozzles and rotational motion of the modified
drill stem (e.g. similar to decoking drill stem) would be designed
to optimize spray coverage of the cross-sectional area of the coke
drum. Full spray coverage of the drum cross-sectional area is not
necessary to achieve desirable results. That is, cooler
temperatures near the drum walls and quench media diffusional
effects will help the quench (chemical and/or thermal) as the
vapors move upward in the coke drum. At the end of the coking
cycle, the modified drill stem is fully retracted. After cooling
and depressurizing the coke drum, the flange is unbolted and the
existing drum derrick 740 is used to extract the modified drill
stem. Maintenance of the modified drill stem system can be
performed during the decoking cycle. Spare modified drill stem
systems are recommended to allow sufficient maintenance time.
[0532] A critical element of this system is the sealing apparatus
715. An example of a potential sealing mechanism is also shown in
more detail in FIG. 7B. This diagram shows a double mechanical seal
used for sealing rotating shafts in high-pressure systems. Due to
the high temperatures (e.g. extracting modified drill stem from hot
coke drum), carbon and/or ceramic materials may be required for
sealing faces. High temperature alloys may also be required for the
metal components. The use of an inert, pressurized liquid or purge
gas can be preferable to balance drum vapor pressures within the
seal, and mitigate leakage into and/or out of the sealing
apparatus. In addition, a specially designed cooling system for the
sealing apparatus may be preferable to dissipate heat from
retracting the modified drill stem from the hot coke drum. To a
certain extent, the purge gas/liquid to balance pressure can also
be used to dissipate heat, as well. One skilled in the art of
sealing rotating shafts can develop a suitable sealing apparatus
for each coker system. Improvements in sealing technologies can
optimize the design required to achieve desired results.
[0533] In coke drums with center draw vapor lines, the vapor line
connections would have to be modified to accommodate the modified
drill stem during the coking cycle and subsequent exchange during
the decoking cycle. One skilled in the art can design the
appropriate vapor line modifications (e.g. special flanged spool)
for each specific application. Similarly, ones skilled in the art
can develop other mechanical devices that could achieve effective
quench (chemical and/or thermal) of the vapor cracking reactions
and accomplish the process advantages of the present invention.
[0534] (2) Exemplary Embodiment to Reduce Vapor Overcracking:
[0535] A combination of both chemical quench and thermal quench is
preferable. This combination quench can offer synergistic effects
and maintain t h e desired results with a lower contribution
required by each. In an exemplary embodiment, hydrogen gas and
condensed coker gas oil may be injected via an exemplary injection
method into the coke drum at the interface of the semi-solid coke
mass, or a reasonable distance above it (e.g. above coke foam). The
quantity of hydrogen addition will vary depending on coker
feedstocks, designs, and coker operations, but should typically be
in the range of 0.1 to 10 weight percent of the coker feed;
preferably 0.1 to 1.0 wt. %. The quantity of coker gas oil will
depend on the desired temperature reduction (5-80.degree. F.;
preferably 5-40.degree. F.) and the coke drum and coker gas oil
temperatures. These quench media can be injected in two separate
streams. The cooled coker gas oil would flow through the center of
a modified, drill stem with concentric-pipes. The cooled hydrogen
gas would flow in the outer annulus to provide heat dissipation and
insulation to prevent excessive vaporization of coker gas oil in
the modified drill stem. The heating of the hydrogen would also
increase the probability of hydrogen free-radicals, but higher
pressures would need to be accommodated in the design (e.g. spray
nozzle). Preferably, two parallel, flat spray patterns would
emanate from the modified drill stem in all directions (i.e.
hydrogen gas on top & coker gas oil liquid on bottom). The
media flows & pressure and the spray nozzles' number and design
will determine the spray coverage and angles. The spray angle 60 to
135 degrees (preferably 90.degree. to 120.degree.) from the
vertical, modified drill stem. A spray angle slightly downward
(from perpendicular to the modified drill stem) is preferable to
compensate for upward vapor flow effects as the media extends
further (radially) from the modified drill stem. One skilled in the
art can make the necessary engineering calculations and design
modifications to address the particular needs of each application
of the current invention.
[0536] (3) Other Embodiments:
[0537] The current invention contemplates other embodiments using
an exemplary injection method to achieve the goals previously
stated. This hydrogen free-radical quench can be less desirable, in
some cases, due to excessive hydrogen requirements, that overload
the fractionator and/or compressor systems. In some cases, the
temperature quench can be the desired embodiment to achieve both
(1) reductions in vapor overcracking and (2) condensation of heavy
aromatics that would be preferably left in the coke, as noted
above. These other embodiments include, but should not be limited
to:
[0538] 1. Hydrogen gas and liquid coker gas oil in a two-phase
injection system (e.g. single-pipe stem)
[0539] 2. Other combinations of thermal quench and chemical quench
media (e.g. hydrogen/steam)
[0540] 3. Thermal quench only: Liquid and/or gas quench media (e.g.
coker gas oil and/or steam)
[0541] Quantity of temperature quench media (e.g. gas oils, steam,
and/or water) depends on the desired temperature drop required to
form the desired porous, sponge coke.
[0542] 4. Chemical quench only: Liquid or gas quench media (e.g.
hydrogen and/or ammonia)
[0543] Quantity of chemical quench media: 0.1 to 20 wt. % of coker
feed; preferably 0.1 to 2.0%.
[0544] Furthermore, any one or combination of the above can be
injected via injection methods other than the exemplary injection
method. Conceivably, more than one modified drill stem can be
active in the same coke drum and coking cycle. Modified drill stems
(e.g. 2 to 8) can be implemented through a similar number of
reinforced flanges in the top of the drum to achieve greater spray
coverage of the drum's cross sectional area. This option may be
preferable for some cokers, particularly for coke drums with an
existing center-flange, vapor draw. One skilled in the art can use
standard calculation and design procedures to develop the most
practical design for each application of the current invention. The
economic incentive for any of these options can be significantly
reduced during periods of high fuel prices, particularly natural
gas.
[0545] 4. Further Optimization of Pet Coke's Fuel Properties and
Combustion Characteristics
[0546] Various options of the present invention can potentially
simplify the core technology and provide additional process
options. An exemplary mechanism of the core technology appears to
be based on the following process steps:
[0547] 1. Production of a modified petroleum coke with improved
carbon adsorption characteristics
[0548] 2. Use of the petroleum coke's carbon adsorption
characteristics in and/or after the coker process to provide
various process options that can optimize its fuel properties and
combustion characteristics
[0549] Though this two-step process is believed to describe the
technical basis for the exemplary core technology, it should be
recognized that the current invention is not limited to this. As
discussed previously, the core technology may depend significantly
on coker feedstocks and design parameters. As such, the core
technology may deviate from this simplified approach.
[0550] A. Production of Petroleum Coke with Activated Carbon
Characteristics
[0551] As previously discussed, various coker process variables
affect petroleum coke crystalline structure. In addition, various
means have been described to modify the coker process variables to
improve the coke crystalline structure and increase VCM content. An
exemplary embodiment provides process options to increase the
production of sponge coke (vs. shot coke or shot coke/sponge coke
mix). The sponge coke of the present invention tends to have higher
porosity than traditional sponge coke. The higher porosity of the
sponge coke crystalline structure of the present invention
preferably provides one or more of the following additional
benefits:
[0552] 1. Within limits, greatly improves cutting from drum &
pulverization (i.e. HGI >100).
[0553] 2. Enhances adsorption quality of this form of activated
carbon (i.e. modified petroleum coke).
[0554] 3. Promotes chemical reactions with petroleum coke due to
increased accessibility via porosity.
[0555] Consequently, the present invention provides additional
options to produce a very high-porosity sponge coke that offers
desirable adsorption characteristics, when properly activated. That
is, the following process options can provide a petroleum coke
crystalline structure with carbon adsorption characteristics,
including high internal and external porosities, high surface area,
and large pore volume:
[0556] 1. Modify coker process variables to consistently produce
high-porosity, sponge coke; and/or
[0557] 2. Inject certain chemical compounds to increase and/or
control coke porosity characteristics.
[0558] Depending on the application, a higher degree of petroleum
coke porosity may be the primary goal (versus VCM content). As a
result, the same process variables may be modified to greatly
improve or maximize internal porosity of the modified sponge coke,
within certain technical limitations. For example, the coke drum
temperature is still the primary process variable to affect the
desired coke crystalline structure. If maximum internal porosity is
desired, an exemplary embodiment may include the lowest drum
temperature that consistently produces a solid petroleum coke with
the highest porosity. That is, the drum temperature would remain
sufficient to prevent unacceptable formation of sticky, pitch-like
material and/or excessive VCM content (i.e., not technically or
economically prohibitive). The addition of aromatic oils (e.g.,
FCCU slurry oils) may be desirable to further reduce this drum
temperature and increase petroleum coke porosity.
[0559] Other chemical compounds can also be injected to increase
and/or control petroleum coke porosity characteristics. Certain
chemical compounds crack at coking temperatures and provide gaseous
components that increase coke internal porosity. The probable
mechanism(s) of this increased porosity may be (1) passage of gases
under pressure rising through the solidifying petroleum coke and/or
(2) altered coke crystal growth. Exemplary gaseous components not
only produce increased porosity, but also allow significant control
of pore sizes (i.e., micropores and mesopores) and volume in the
resultant pet coke. Hydrogen, light hydrocarbons (butanes and
lighter), and light, inert oxygen derivatives (CO.sub.2l H.sub.2O,
etc.) may provide more desirable porosity characteristics, but
other gases can be used, as well. Exemplary chemical compounds for
injection include, but are not limited to, recycled plastics,
hydrogen, wood wastes, low-rank coals, and steam. Solids may
require fine pulverization (e.g. <100 mesh) prior to injection
into the coker. Though several injection points are feasible, an
exemplary point of injection is the recycle streams downstream of
the fractionator. The quantity of injected compounds can be
severely limited by coker pressure drop, fractionator design, and
contaminant limitations in the traditional coker operation.
However, the modified coker operation of the current invention
typically debottlenecks existing operations, creating excess coker
capacity to be used in this manner.
[0560] An exemplary embodiment for this first process step can
include one or more of the following:
[0561] 1. Minimum coke drum temperature that consistently produces
solid pet coke w/o pitch-like material
[0562] 2. Injection of recycled plastics, wood wastes, and/or
hydrogen that optimize porosity characteristics
[0563] As noted previously, desired process conditions may vary
with (1) coker feedstocks, (2) coker design and operational
constraints, and (3) product constraints. However, this minimum
coke drum temperature may be lower in most cases, but may still be
750.degree. F. to 850.degree. F. Also, minor equipment
modifications (e.g. new coke drum insulation) may be necessary to
assure even temperature distributions across the coke drum. Ones
skilled in the art of coking and adsorption media (particularly
activated carbon) would be capable of determining the optimal
design and operation for particular coker and combustion
applications.
[0564] Other embodiments for this first process step include
various other combinations of the coker process variables that (1)
achieve the desired changes in coke crystalline structure and VCM
content and (2) provide sufficient adsorption quality in the
modified petroleum coke for optimizing fuel properties and
combustion characteristics. Also, selecting and adding certain,
low-cost cracking stocks (e.g. various industrial by-products
and/or non-hazardous wastes) to the coker feed can be desirable to
achieve higher VCM increases. Embodiments, other than the examples,
may be desirable in some cases to optimize the technology relative
to certain constraints (e.g. causing excessive VCM content and/or
exceeding other coker design or operational parameters). For
example, the other various embodiments of the present invention are
still valid scenarios to create a premium petroleum coke with
improved fuel properties and combustion characteristics.
[0565] The results of this first process step is the production of
a modified petroleum coke with a high porosity sponge coke
crystalline structure (vs. low porosity sponge coke or other
crystalline forms). In addition, the lower severity coking
operation will typically leave more VCM in the coke, from reduced
cracking reactions. Depending on the coker feedstocks and design
parameters, the modified petroleum coke can have modest to good
adsorption qualities, and may increase VCM 3-10%. In some cases,
the adsorption quality may be sufficient to justify uses in
traditional activated carbon systems, with or without subsequent
use as a fuel. In these cases, steam stripping the residual VCM
content in the initial phases of the quench cycle can provide
sufficient activation of the carbon adsorption surface. In the
other cases, the modified petroleum coke provides a superior solid
fuel that can be further optimized for most solid fuel combustion
applications. In addition to the use of the premium petroleum coke
of the present invention in utility boilers with pulverized coal
(PC) burners, the premium petroleum coke provides benefits in other
combustion applications, as well. Other combustion applications may
include, but are not limited to (1) other solid fuel boilers
(utilities, industries, IPPs, etc.) and (2) rotary kilns in the
cement and hazardous waste industries.
[0566] This first process step provides benefits to the crude oil
refinery similar to those discussed elsewhere in this application.
The major benefits attributable to this first process step are:
[0567] 1. Reduced Heater Severity: Lower Heater Outlet Temperatures
(.about.50.degree. F.-180.degree. F. Lower)
[0568] a. Reduced Fuel Consumption: MMBtu/Hr and Btu/Lb. Feed
(.about.10-30+%)
[0569] b. Greater Heater Capacity; Faster Drum Fill Rate: Reduce
Hours Per Cycle (.about.2-6 Hours)
[0570] c. Reduced Heater Spalling, Tube Failures, Unscheduled
outages, & Equipment Maintenance
[0571] 2. Reduced Fractionator Load: Higher Coke Production
(Ton/MBbl Feed); .about.5-10% Less Load
[0572] 3. Increased Coker Capacity: 10-40+% Increase
[0573] a. Reduced Cycle Times: 18-24 Hours Down to 12-16 Hours Per
Cycle
[0574] I. Coking Cycle: Faster Drum Fill Rates
[0575] II. Quench: Eliminate "Big Steam" Strip and
[0576] III. Coke Cutting Cycle: Reduce Cutting Time (HGI
>100)
[0577] 4. Improved Operation & Maintenance: Coker & Other
Process Units: Less HGO; Better Quality
[0578] 5. Increased Refinery Capacity: .about.0-25% Due to
Debottlenecking of Coker Capacity Limitations
[0579] This first process step also provides benefits to the
premium petroleum coke user. As noted earlier, this first process
step dramatically changes the petroleum coke's crystalline
structure. Traditional refinery coking methods produce a petroleum
coke that has a dense, shot coke crystalline structure (e.g.
consistency of marbles) or a shot coke/sponge coke blend with
varying crystalline composition of densities averaging 50 to 60
lb/ft.sup.3. On the other hand, the coker modifications of the
present invention produce a less dense sponge coke with much
greater porosity. This modified crystalline structure is much more
conducive to efficient carbon burnout levels (e.g. >99%) without
the need for long residence times in high temperature zones
exceeding 1500.degree. F. and/or restricted to refractory lined
furnaces. In addition, the very porous, sponge-coke crystalline
structure gives the petroleum coke of the present invention (1)
adsorption characteristics for optimizing fuel properties and (2)
desirable capabilities as activated carbon in adsorption
applications.
[0580] Optimization of the technology of the present invention can
be used to further control coke porosity for fuel and carbon
adsorption applications. That is, the increased coker throughput
capacity (discussed above) provides the ability to introduce
chemical compounds with certain cracking and vaporization
characteristics that tend to increase the amount of voids in the
petroleum coke of the present invention. These chemical compounds
may include, but are not limited to industrial by-products,
non-hazardous wastes, or low cost products. Traditional coking
processes normally cannot take advantage of this novel technique
due to precious limits on coker feed throughput, relative to the
refinery's crude throughput. In addition, these chemical compounds
may not only increase porosity and improve carbon adsorption
characteristics, but also potentially provide alternative sources
of VCMs (versus loss of light ends from traditional coker
feedstocks).
[0581] B. Uses of Activated Carbon Characteristics of Modified
Petroleum Coke
[0582] The second major process step is the use of the modified
petroleum coke's activated carbon characteristics to further
optimize its fuel properties and combustion characteristics.
Various process options have been discussed to optimize the fuel
properties and combustion characteristics of the modified petroleum
coke. The potential role of carbon adsorption characteristics
(e.g., activated carbon) in these process options will now be
discussed. Some of the fuel optimization process options may be
external to the coker process (e.g. third-stage desalter). In
contrast, other options may be initiated in the coking process
(i.e. in-situ). In addition, several fuel optimization process
options have been added.
[0583] The first major process step produces a modified petroleum
coke with highly porous, sponge coke crystalline structure and
carbon adsorption characteristics. This modified, premium petroleum
coke provides physical and chemical properties to create the
following process options in the coking process. These options can
further optimize its fuel characteristics:
[0584] 1. Modified Crystalline Structure: Very porous, sponge coke
w/HGI >100; Adsorption quality
[0585] 2. Addition of High Quality VCMs: 18-30 wt. %; Uniformly
distributed with controlled quality
[0586] 3. Ash Quality Improvement Options: Removal of troublesome
metals; Mitigate ash fusion
[0587] 4. Sulfur & Nitrogen Content Reduction Options: Various
methods & degrees/incremental costs
[0588] 5. Integration of SOx Sorbents: Scavenge coke sulfur;
Uniformly distributed w/controlled quality
[0589] 6. Integration of Oxygen Compounds: Options to reduce
combustion air; Uniformly distributed
[0590] 7. Optimal Use of Inherent Oxidation Catalysts: Maintain
optimal levels & enhance metal catalysts
[0591] 8. Optimal Use of Carbon Adsorption Character Mercury &
other air toxics; HCs & chlorine
[0592] These reliably, controlled process options (available at
various incremental costs) allow a user to optimize the fuel
properties in a manner that maximizes benefits and/or minimizes
equipment and operational modifications in the user's facilities.
Hence, unlike most other fuels (e.g. coals), the petroleum coke of
the present invention can be consistently produced with optimal
fuel properties and combustion characteristics. The economic and
technical limits of these fuel optimization process options (and
their associated incremental costs) will depend on various factors,
including (1) the crude oil refinery, (2) the relative size and
design of its process units, (3) the crude blend, and (4) the coker
feed blend. Discussions for each of these fuel optimization process
options follow:
[0593] (1) Modified Crystalline Structure:
[0594] Most of the desired changes in coke crystalline structure
can be achieved in the first major process step. However, the high
internal porosity and pore volume of the modified petroleum coke
allow chemical reactions on the internal surface of the coke to
further change coke crystalline structure. For example, chemical
binders may be added in to mitigate coke storage, handling, and
pulverization issues, including friability, dust, and
explosability. In most applications, these issues are not expected
to be prohibitive. In addition, the timing and method of cutting
this modified coke from the coke drum can physically alter the coke
crystalline structure.
[0595] (2) Addition of High Quality VCMS:
[0596] An exemplary process of the present invention can provide
the addition of volatile combustible materials (VCMs) in two
distinct steps. The first step increases VCMs from the coker feed
via operational changes (e.g. lower coke drum temperature) in the
cracking/coking portion of the delayed coking process (i.e. the
first major process step, described above). In the second step,
VCMs are added to the coke during the quench cycle in a manner that
uniformly distributes the VCMs throughout premium petroleum coke's
porous crystalline structure. In both steps, various by-products
and/or wastes can be selected and uniformly integrated (e.g. mixed
in coker feed in step 1) to achieve the desired fuel properties at
low costs. Alternatively, standard hydrocarbon products, such as
No. 6 fuel oil, can also be used, but normally at a higher price.
Collectively, the quantity, quality, and desired effects of how the
volatile combustible materials are added to traditional coke can be
controlled to reasonable specifications and consistency. In this
manner, high quality VCMs can be added uniformly to the coke in
sufficient quantity to dramatically improve flame initiation and
carbon burnout.
[0597] In an exemplary embodiment, desirable VCMs (quality and
quantity) can be added to the coke quench media, preferably water
or other aqueous solutions. The carbon adsorption characteristics
of the modified petroleum coke will provide sufficient adsorption
of these VCMs (particularly non-polar VCMs) and uniformly
distribute them within the coke's internal pores. The optimal
timing, temperature, and rate for VCM/quench media addition will
depend on the VCMs selected and the desired effect (e.g. VCM
devolatilization in char burnout vs. combustion initiation). Other
embodiments can include post coker treatment (e.g. rail cars) to
allow additional time for other options to be completed in the coke
drums during the regular coker cycle times. However, if the cycle
time becomes a constraint in pursuing all of the desirable process
options, coke drum additions may be preferable (e.g. add 3rd coke
drum in cycle). Coke drum additions can provide further petroleum
coke treatment time before, after, or intermediate stages of quench
to maintain desired temperatures for the specific treatment
technology.
[0598] (3) Ash Quality Improvement Options:
[0599] Various process options can substantially improve combustion
ash quality by reducing certain, troublesome metals in the
petroleum coke. These metals can be reduced in various degrees by
treatment of the refinery's crude oil blends, coker feeds, and/or
the coke itself. The present invention options to remove these
metals of concern in all of these treatment methods. First,
treatment of the crude oil blends typically requires minor
equipment and operational modifications to the existing crude oil
desalting system(s). Secondly, partial or full treatment of the
coker feeds can be achieved by various methods, including
hydrotreating, hydrodesulfurization, demetallization, or third
stage desalting. The desired option will depend on the
characteristics of the refinery's crude blend, its various process
units, and product slate. In many refineries, the addition of a
third stage desalting unit (i.e. coker feed) can require (1) modest
capital and operating costs and (2) a couple of years time to
engineer and construct. All of the above pre-coker treatments also
improve the operation and product quality for other refinery
process units. Thus, the incremental costs attributed to the
premium petroleum coke for these treatments may be minimal to
modest.
[0600] In an exemplary process of the present invention, the
modified pet coke can be treated to remove metals during (in-situ)
or after the coking process (e.g. in rail cars). The high internal
porosity of the modified petroleum coke and the pressurized flow of
the quench media provides the opportunity to chemically treat
and/or remove exposed metals of concern. Chemical products and/or
by-products or wastes with chemically active components can be used
to initiate and complete the desired reactions. The resulting
compound (more polar & water soluble) can be washed and removed
from the modified coke. For example, spent phenolic acid from the
refinery's lube oil extraction unit may be added to the quench
media for coke demetallization. This organic acid can react with
undesirable metals exposed on the internal surface of the modified
coke. Residual phenolic acid will add oxygen (discussed below). The
optimal timing, temperature, and rate for reactants/quench media
addition will depend on the metals reactive chemicals selected and
the desired effects (e.g. metals removal vs. making chemically
inert).
[0601] The combination of all these metals removal methods may not
be required to achieve desired results. In fact, most applications
may require only one or two treatment methods, at most. The various
metal removal methods simply offer the flexibility of various
options to optimize a given refinery and achieve the same goal at
the lowest possible cost.
[0602] (4) Sulfur and Nitrogen Content Reduction Options:
[0603] Additional process changes can reduce the sulfur and
nitrogen contents of the petroleum coke to various degrees with
incremental increases in cost. As such, this modified petroleum
coke can be obtained in regular or desulfurized grades.
[0604] The sulfur content can be reduced in various degrees by (1)
changing the coker feed blend, (2) partial or full treatment of the
coker feeds, and/or (3) treatment of the coke itself. Again, the
technology of the present invention offers sulfur reduction options
in the various treatment methods, particularly for treating the
coke during or after the coking process. First, lower sulfur feeds
in the coker feed blend can significantly reduce the sulfur content
of the petroleum coke. Optimization of the technology (i.e. via
increased coker throughput capacity discussed above) provides the
ability to introduce industrial by-products, non-hazardous wastes,
or low cost products with lower sulfur content. Traditional coking
processes normally cannot take advantage of this novel technique
due to precious limits on coker feed throughput, relative to
refinery throughputs. Second, partial or full treatment of the
coker feeds can be achieved by various methods, including
hydrotreating and hydrodesulfurization. Finally, the treatment of
the petroleum coke, during or after the coking process, can take
many forms: solvent extraction, reaction with strong reducing
agents, and/or hydrotreating.
[0605] In an exemplary process of the present invention, the
modified petroleum coke can be treated to remove sulfur and/or
nitrogen during (in-situ) or after the coking process (e.g. in rail
cars). The high internal porosity of the modified petroleum coke
and the pressurized flow of the quench media provides the
opportunity to chemically treat and remove exposed sulfur and/or
nitrogen. Chemical products and/or by-products or wastes with
chemically active components can be used to initiate and complete
the desired reactions. The resulting compound (more polar &
water soluble) can be washed and removed from the modified coke.
For in-situ desulfurization or denitrification in the coker
process, the coke drums of a delayed coker may provide any one or
any combination of the following desulfurization techniques:
solvent extraction, reaction with strong reducing agents,
hydrotreating, and/or biodesulfurization). For example, spent
phenolic acid from the refinery's lube oil extraction unit can be
used as a solvent in the coke quenching cycle to extract sulfur
(and nitrogen) from the petroleum coke. This organic acid can react
with sulfur (and nitrogen) exposed on the internal surface of the
modified coke. Also, strong reducing agents, such as hydroxides of
calcium, magnesium, sodium, and/or potassium, can be used in the
coke quenching cycle to react with and remove sulfur from the coke.
Hydrotreating is essentially the introduction of hydrogen at high
temperatures to saturate the hydrocarbon compounds, replacing
sulfur in complex chemical structures. This treatment can be used
alone or in conjunction with other treatments to enhance their
effectiveness. The use of hydrogen to increase the porosity of the
modified coke (discussed above) provides intimate diffusion within
the coke structure, normally the slow reaction step. The optimal
timing, temperature, and rate for reactants/quench media addition
will depend on the sulfur compounds/reactive chemicals selected and
the desired techniques.
[0606] In all of these desulfurization methods, the non-thiophenic
sulfur (i.e. .about.20-30 wt. %) may be more easily removed.
Thiophenic sulfur is not readily separated from its complex
hydrocarbon compounds and generally requires higher temperatures
(e.g. >600.degree. F.) to break its relatively stable, chemical
bonds. However, the cracking/coking portion of the coker process
can be sufficient to convert complex, sulfur compounds to
non-thiophenic forms. Consequently, a 20-30% reduction sulfur
content can be readily achieved with relatively simple applications
of these methods. Coke treatments during or after the coke
quenching cycle provide greater sulfur removal potential. Any
additional reductions of coke sulfur content can be much harder to
achieve, with greater incremental costs (i.e. more money per ton of
sulfur reduced).
[0607] (5) Integration of SOx Sorbents:
[0608] The technology of the present invention anticipates the need
to achieve incremental reduction of sulfur oxides in the combustion
and air pollution control systems. The ability to convert the
existing particulate control device (PCD) into a sulfur oxides
control is a major feature of the present invention. That is, the
much lower ash content (>90 wt. % lower) of the petroleum coke
of the present invention frees up available capacity in the
existing PCD to collect sulfur oxides that are converted to dry
particulates upstream of the PCD. Methods of injecting various dry
sorbents (e.g. limestone, hydrated lime, sodium hydroxide, etc.) to
the fuel and combustion products have been commercially proven.
However, dry sorbents mixed in with the fuel typically are less
effective due to sintering of its reactive crystalline structure in
the high temperature zones of the furnace. Sorbents injected into
the flue gas (at various points in the boiler or flue ducts)
usually require high sorbent to sulfur molar ratios due to various
factors. Three major factors, which prohibit the desired chemical
reactions, are:
[0609] (1) Calcination process to convert injected dry sorbent to
more reactive form (e.g. CaCO.sub.3 to CaO)
[0610] (2) Bulk diffusion of gaseous sulfur oxides to the solid
sorbent, and
[0611] (3) Diffusion of sulfur oxides through sorbent pores and
CaSO.sub.4 layers (e.g. blocking pores).
[0612] An exemplary process of the present invention provides
process options for uniformly adding SOx sorbents to the modified
petroleum coke to alleviate these reaction constraints. Desirable
SOx sorbents (quality and quantity) can be added to the coke quench
media, preferably water or other aqueous solutions. The carbon
adsorption characteristics of the modified petroleum coke will
provide sufficient adsorption of these sorbents (particularly
non-polar sorbents, such as Ca(OH)2) and uniformly distribute them
within the coke's internal pores. The integration of the sorbent in
the very porous petroleum coke of the present invention has several
advantages. First, sintering of the reactive sorbent structure is
dramatically reduced, since the calcination and crystallization of
the reactive sorbent form does not occur until after the flame's
high temperature zones. That is, the sorbent (integrated in the
char) does not calcine until char burnout in the lower temperature
zones of low NOx combustion modes. Secondly, the reaction limiting
factors attributed to the sorbent calcination and crystallization
steps are greatly reduced. These steps occur well ahead of the SOx
reaction zone of optimal temperature. Thirdly, the sorbent is
integrated in the very porous sponge crystalline structure of the
coke, where most of the remaining sulfur is located. Consequently,
the bulk diffusion reaction limits (Item 2, above) are
substantially reduced due to relative close proximity of the high
concentrations of SOx and high concentrations of reactive sorbents.
Finally, the very fine pulverization of the highly-porous petroleum
coke of the present invention (>90% through 200 mesh) can
significantly reduce reaction limits caused by blockage and limited
diffusion to reactive pore sites (Item 3, above). The very porous
structure of finer particles creates greater reactive surface areas
that are less restrictive. The optimal SOx sorbent concentration,
timing, temperature, and injection rate for quench media addition
will depend on the sorbents selected and the desired impacts.
[0613] Other embodiments can include use in combination with sulfur
reduction options and post-coker treatments. The use of strong
reducing agents, such as calcium hydroxide, for coke
desulfurization will often leave residual reacted sulfur compounds
(not washed away) and residual calcium sorbents. The residual
calcium compounds will still be effective SOx sorbents: scavenging
sulfur and converting to particulates for collection by the
existing particulate control device. Post coker treatment (e.g.
rail cars) can allow additional time for other options to be
completed in the coke drums during the regular coker cycle times.
However, if the cycle time becomes a constraint in pursuing all of
the desirable process options, coke drum additions may be
preferable (e.g. add 3d coke drum in cycle).
[0614] (6) Options for Integration of Oxygen Compounds:
[0615] An exemplary process of the present invention provides
process options for uniformly adding oxygen content to the modified
petroleum coke to reduce combustion air requirements. Desirable
oxygen-containing compounds (quality and quantity) can be selected
and added to the coke quench media, preferably water or other
aqueous solutions. The activated carbon characteristics of the
modified petroleum coke can provide sufficient adsorption of these
oxygen sources (particularly non-polar chemicals, such as phenols)
and uniformly distribute them within the coke's internal pores. The
type of oxygen sources can ultimately impact the fuel's combustion
characteristics. Though practically all oxygen content of the fuel
(except water) will be productive in reducing combustion air, some
types of oxygen sources can be preferable to others. For example,
oxygen compounds that are chemically bound in a heavier
hydrocarbons can be more beneficial to burning the char and help
reduce excess air levels as well as theoretical combustion air
levels. That is, these compounds (unlike alcohols) will not readily
volatilize at lower temperatures, and provide more effective
oxidation of the char without higher excess air. Another example
would be the injection of phenols for desulfurization (described
above), and the residual, unreacted phenols providing added oxygen
content.
[0616] (7) Optimal Use of Inherent Oxidation Catalysts:
[0617] The high metals content of petroleum coke is often believed
to be a problem, particularly vanadium and nickel. Options to
reduce the coke metals content can alleviate these concerns
(discussed above). However, these metals can be advantageous as
combustion catalysts in certain firing modes. Catalytic oxidation
can be very effective in improving combustion in low temperature
zones with low oxygen availability, conditions often associated
with low NOx combustion. Also, Vanadium catalysts are often used in
the presence of ammonia or other reagents to decompose or oxidize
nitrous oxides to molecular nitrogen and oxygen. For example, low
NOx combustion firing modes have dramatically increased the
unburned carbon of many pulverized coal boilers. This not only
substantially reduces boiler efficiency, but dramatically increases
the carbon content of the ash, as well. Ash carbon contents >5%
can turn ash reuse sales of about $15/Ton to ash disposal costs of
about $ 20/Ton. In this situation, catalytic oxidation caused by
the metals content of the petroleum coke of the present invention
can be critical to economic viability. That is, leaving significant
metals content in the petroleum coke of the present invention can
be very helpful, particularly with a modest coke portion in
coal/coke blend. In addition, the catalytic oxidation can improve
NOx performance, while reducing the need for substoichiometric
combustion with severely reducing (corrosive) atmospheres that
increase tube failures.
[0618] A process of the present invention recognizes the potential
benefits to (1) maintain optimal levels of certain metals (e.g.
vanadium and nickel) and (2) enhance their oxidation catalyst
characteristics. First, the optimal levels of the metals of concern
can be determined for each combustion application. Once quantified,
the demetallization processes, discussed above, can be adjusted to
achieve the optimal levels (though possibly not independently).
Secondly, the desirable oxidation catalyst characteristics can be
further enhanced by chemical or physical treatment. That is, the
high internal porosity of the modified petroleum coke and the
pressurized flow of the quench media provides the opportunity to
chemically and/or physically treat exposed oxidation catalysts. For
example, chemical treatment may be used to activate the oxidation
catalyst and make it more reactive.
[0619] (8) Optimal Use of Carbon Adsorption Characteristics:
[0620] As discussed previously, the first major process step
produces a modified petroleum coke with carbon adsorption
characteristics (i.e. high internal porosity and pore volume).
Consequently, this modified petroleum coke can have the physical
and chemical properties required for many carbon adsorption
applications (e.g., activated carbon). The internal and external
porosities can approach and exceed 60% and 35%, respectively. The
pore size can range from 5-50 angstroms. Thus, the surface area of
the petroleum coke of the present invention can approach and exceed
600 square meters per gram. These carbon adsorption characteristics
compare favorably with those properties for activated carbon form
other sources. As such, the modified petroleum coke can be useful
in traditional activated carbon technologies, as well as carbon
adsorption in combustion processes.
[0621] A process of the present invention can produce adsorption
quality carbon, which can be used in traditional activated carbon
technologies: water treatment, vapor recovery, adsorption of
various hydrocarbons, metals and/or other toxics form gaseous or
liquid streams. The adsorption properties of this modified
petroleum coke can be enhanced by steam-stripping in the quench
cycle in the carbon adsorption system or otherwise. After serving
its useful life in carbon adsorption, this premium pet coke can be
further used as fuel or activated carbon in combustion processes.
In either case, treatment (e.g. one final regeneration step) may be
necessary to sufficiently reduce or remove harmful contaminants
(prior to combustion) to avoid undesirable air pollutants and/or
ash constituents. Alternatively, this carbon adsorption coke can be
further used as activated carbon in combustion processes.
[0622] Another process of the present invention produces modified
petroleum coke with adsorbent characteristics (with or without
steam activation) that can be effectively used for carbon
adsorption in combustion processes. In a manner similar to steam
activation, the combustion process itself can potentially activate
the unburned coke char and promote carbon adsorption mechanisms in
the flue gas. The relative quantity of this adsorption carbon from
unburned premium petroleum coke can be adjusted by controlling the
fuel blend, pulverization fineness, excess air, and/or other
parameters of the combustion process. Alternatively, other
activated carbon (e.g. see above paragraph) can be added to the
fuel or the flue gas to provide higher concentration of activated
carbon in the flue gas. In this manner, the unburned premium
petroleum coke and/or used adsorption carbon from the present
invention can adsorb mercury, dioxins, furans, other air toxics,
and other undesirable pollutants from the flue gas, including
carbon dioxide, SOx, and NOx. The presence of sulfur, available in
the coke, can enhance the adsorption of mercury, a growing concern
of power generation facilities. In this manner, the premium coke
can achieve further reduction of environmental emissions from the
combustion process.
[0623] 5. Additional Methods to Increase Pet coke Porosity &
Adsorption Character
[0624] As noted previously, various methods can be used to modify
the pet coke crystalline structure, preferably to a highly porous,
sponge coke. This modified crystalline structure can improve the
carbon adsorption characteristics of the petroleum coke. In these
cases, various chemical agents can be uniformly added to the
petroleum coke in its inner voids, based on carbon adsorption
technology. In this manner, the modified crystalline structure of
the petroleum coke can be used in various carbon adsorption
applications and/or to further modify the coke's fuel properties,
combustion characteristics, and/or other coke qualities. Additional
methods (e.g. other embodiments) are described that improve the pet
coke's internal porosity and carbon adsorption characteristics. The
first two methods (i.e. coker operation/modified feed and
plastics/rubber addition) provide further details of similar
methods, described previously. The last three methods (i.e. coke
hydroprocessing, coke extraction, and coke chemical activation) are
additional embodiments that can achieve the intent and needs of the
current invention.
[0625] It should also be noted that all of these methods could be
used for purposes other than increasing pet coke porosity and
enhancing adsorption characteristics. That is, these methods have
additional benefits (e.g. wastes recycling) and can be used
independent of their ability to increase coke porosity and improve
pet coke adsorption characteristics. Thus, the present invention is
not limited to their use to increase porosity, but also includes
these methods for other purposes.
[0626] A. Carbon Adsorption Characteristics
[0627] Various porous materials demonstrate some degree of
adsorption character. The internal pore structures of these solid
materials (adsorbents) provide an internal surface where various
chemical compounds (adsorbates) in a passing fluid can be held by
Van der Waals and/or other molecular forces. In general, good
adsorption character is defined by various measured parameters
related to the internal pore structure of the adsorbent. These
parameters provide relative comparisons that help screen potential
adsorbents. However, the selection of the desired adsorbent depends
on other factors associated with the adsorbate system
characteristics. These selection processes usually involve
case-by-case analyses.
[0628] The shapes and sizes of pores are an important factor in
carbon adsorption technology. Pores are typically classified into
three different size categories (as defined by IUPAC): micropores,
mesopores, and macropores. Micropores have a diameter of <2 nm
(nanometers). Mesopores have diameters between 2 and 50 nm.
Macropores have diameters >50 nm. Micropores and mesopores
primarily give porous carbon materials their adsorption capacities.
These types of pores are often formed during the process of
activation. Activation is basically further development of pores in
low porous raw material by chemical reactions. Traditionally,
`physical` activation (i.e. oxidation with gases: steam, carbon
dioxide, or air) and chemical activation (i.e. reaction with
chemical agents prior to heat treatment) are two processes that
give fundamentally different pore structures.
[0629] Various measured parameters of pore structure provide
relative indications of adsorption performance. Three of the most
common adsorption parameters are (1) internal porosity, (2) pore
size distribution, and (3) internal surface area. Carbonaceous
materials with very high porosity and large surface areas generally
provide good adsorption qualities. Activated carbons are highly
porous, carbonaceous materials that provide exceptional adsorption
capabilities. One of the most widely used parameters to measure the
effectiveness of pores in activated carbons is the total surface
area or BET surface area. BET surface area uses a projection model
and adsorption data to account for multi-layer adsorption effects.
Most of the total surface area is found in the micropores. Typical
data 2 for an activated carbon are: >500 square meters per gram
(m Ig) in micropores, 10 to 100 m.sup.2g in mesopores, and <10
m.sup.2/g in macropores.
[0630] These adsorption parameters are useful for general
comparison of potential adsorption character among adsorbents and
provide preliminary indication of relative adsorption performance.
However, the desired adsorbent for a particular application depends
on (1) the physical/chemical characteristics of the adsorbate, (2)
the physical/chemical characteristics of the fluid system
containing the adsorbate, and (3) concentration of the adsorbate in
the fluid system. Consequently, the desired adsorbent is normally
determined on a case-by-case basis. In many applications, only part
of the total surface area is accessible for the molecules to be
adsorbed. In these cases, molecules, which are to be adsorbed, are
too large to fit into the micropores. For example, most
liquid-phase applications require the adsorption of high molecular
weight materials. Most of these larger compounds, by their size,
are excluded from a large part of the micropore system. As such, a
carbon with high number of mesopores is required, and a carbon with
high total surface area of predominantly micropores provides no
value. Ideally, the carbon should have a large number of pores,
which are just slightly larger than the size of the molecules to be
adsorbed. Smaller pores are inaccessible, and much larger pores
provide relatively little surface area per unit volume.
Consequently, the activated carbon industry characterizes their
carbons by adsorption properties rather than pore structures.
[0631] In conclusion, carbon adsorption character is more of an art
than science. Adsorption characteristics can vary considerably and
are not absolute in terms of measured adsorption parameters. As
such, it is difficult to specifically define adsorption character
by specific ranges of analytical measurements of adsorption
parameters. Instead, adsorption character is more appropriately
dealt with on a case-by-case basis. That is, the best carbon
adsorption character is highly dependent on the specific
adsorbate(s) and conditions of a particular adsorption application.
Therefore, the ranges of specifications for desired carbon
adsorption character are provided as a guide for most situations.
However, variance outside of these ranges can occur in some cases
due to (1) coker feedstocks and operations, (2) characteristics of
targeted adsorbate(s), (3) physical and chemical conditions of
adsorption, and/or (4) other factors. Thus, the present invention
is not limited to these specific ranges, but also includes variance
from these ranges, wherein the spirit of the present invention and
its advantages are maintained.
[0632] B. Improved Carbon Adsorption Character: Modified Operation
and/or Feed
[0633] The porosity and adsorption characteristics of petroleum
coke can vary substantially due to variations in the coker
feedstocks, design, and operating conditions. As discussed
previously, there are three basic types of pet coke crystalline
structures from a delayed coking process: shot, sponge, and needle.
These basic coke crystalline structures have substantially
different porosity and adsorption characteristics. The porosity and
adsorption character within these crystalline classifications and
their associated transition zones can also vary considerably.
[0634] The shapes and sizes of the pores in the petroleum coke can
play a major role in its carbon adsorption characteristics and
capacities. Adsorption qualities of traditional activated carbons
may not be necessary for pet coke fuel enhancements. However, pet
coke with adsorption characteristics approaching this level can be
desirable for fuel enhancements and/or other adsorption
applications, if economically practical.
[0635] (1) Petroleum Coke Crystalline Growth:
[0636] Modifications of the pet coke crystalline structure have
been previously discussed. The effects of coker design, feedstocks,
and operating conditions were described relative to two coking
mechanisms: asphaltic and thermal coking. The resulting three types
of coke crystalline structure (shot, sponge, and needle) were also
discussed. However, further discussion of the coker crystalline
growth is appropriate to describe the pet coke's carbon adsorption
characteristics. In these complex chemical structures, there is
much debate about how and when the pet coke crystals form. It is
not clear when the formation of the chemical bonds of petroleum
coke ends and the formation of pet coke crystals begins. In
general, both coking mechanisms and pet coke crystal growth occur
sequentially in the coking and decoking cycles of the delayed
coking process. The following theory of coke formation and
crystalline growth is presented as a basis for understanding the
methods described previously. However, the present invention should
not be bound or limited by this theory of operability.
[0637] In the formation of shot coke, the asphaltic coking
mechanism is predominant. In this case, the coker's cracking
reactions cause conversions that shift the solvent properties of
the oil mixture (e.g. the loss of aliphatic and napthenic chains),
and disrupt the colloidal suspension of the asphaltenes and resins.
As a result, the asphaltenes and resins are precipitated in a
manner that forms a highly cross-linked structure of amorphous
coke. This desolutation is primarily physical changes with limited
alteration of chemical bonds (mostly cross-linking between
asphaltenes, resins, and some aromatic compounds). The precipitated
coke tends to form imperfect spherical balls, ranging in size from
<0.25 inches to >10 inches. This amorphous coke crystalline
structure is commonly called shot coke. At the higher temperatures
of the coking cycle, the shot coke tends to remain in a two-phase,
solid/liquid residue. The pressurized liquid/gas coker feed and the
vapors from the cracking reactions flow upward through this coke
mass. However, the shot coke structure is very dense, and does not
allow the penetration or permeation by these gases. As such, these
gases flow around the shot coke (e.g. channeling). Similarly, in
the decoking cycle, the stripping steam and cooling media pass
between the balls of shot coke. Consequently, shot coke maintains a
very dense, amorphous coke structure with limited porosity, even
after the cooling of the decoking cycle. Shot coke tends to have
high impurities concentrations and high C/H ratios. Typically, this
amorphous coke is undesirable for anode manufacture and coker
operations (e.g. blockage of drainage in decoking cycle &
safety).
[0638] In the formation of needle coke, the thermal coking
mechanism is very predominant, with little to no asphaltic coking
mechanism occurring. In this case, coke is typically made from
highly aromatic coker feedstocks (e.g. thermal tars or decanted
oils). As such, the concentration of asphaltenes and resins in the
coker feed is very low. The thermal coking mechanisms cause the
condensation and polymerization of the heavy hydrocarbons (mostly
aromatics). Without the asphaltenes, resins, and their associated
impurities, this needle coke crystalline structure is uniform,
tightly packed, and rigid. In the coking cycle, the needle coke
crystalline structure is initiated, but tends to remain in a
two-phase, solid/liquid residue due to the higher temperatures. The
pressurized coker feed liquid and cracked gases flow upward through
channels between crystalline matrices in the semi-solid coke mass.
In the decoking cycle, the thermal coking mechanism continues to a
limited extent. The stripping steam and cooling media pass through
matrix channels in the solidifying coke mass. By the end of the
decoking cycle, the needle coke is normally cooled sufficiently to
form a very crystalline solid that can be cut and extracted from
the coke drums. Ultimately, the needle coke has numerous
unidirectional pores that are very slender, elliptical, and largely
interconnected. The thick coke walls surrounding the voids are
fragile, and form needle-shaped pieces, when broken.
[0639] The formation of sponge coke can be described as an
intermediate coke classification between shot and needle coke. The
thermal coking mechanism is predominant, but the asphaltic coking
mechanism occurs, as well. In this case, the ratio R (i.e.
asphaltic coke to thermal coke) is sufficiently low, and the
asphaltenes and resins mostly remain in solution. The thermal
coking mechanism causes condensation and polymerization of the
heavy hydrocarbons (e.g. aromatics), and some cross-linking to
asphaltenes and resins. In this manner, the asphaltenes and resins
are integrated in a complex coke crystalline structure, and
apparently behave like impurities in the crystallization of a pure
compound. That is, the polymerization and cross-linking of the
heavy aromatics with the asphaltenes and resins tend to form a
non-symmetric (i.e. less uniform) and flexible (less rigid)
crystalline structure. In the coking cycle, the formation of sponge
coke is initiated, though it still remains semi-solid at these
higher temperatures. The pressurized coker feed liquid and gas
vapors from the cracking reactions penetrate this crystalline
structure as they flow upward through the coke mass, initiating the
development of pores of various sizes. In the decoking cycle, the
thermal coking mechanism continues to a limited extent. As the
stripping steam passes through the semi-solid coke mass, more pores
are created in the sponge coke. Additional pores are created in the
sponge coke, as the cooling media (water and/or low
pressure/temperature steam) pass through the solidifying coke mass.
By the end of the decoking cycle, the sponge coke is normally
cooled sufficiently to a solid form for cutting and extraction from
the coke drums. Ultimately, the sponge coke has numerous pores that
are random with limited interconnectedness. The coke walls vary in
thickness. Even so, the sponge coke has significant porosity and
carbon adsorption character, as evidenced by the removal of cracked
liquids from the pet coke in the decoking cycle release via steam
stripping. During calcination, lighter hydrocarbons have also been
released at higher temperatures, even after steam stripping.
[0640] Transitions between these three types of coke crystalline
structure are not clear-cut. That is, certain ranges of the ratio R
(i.e. asphaltic coke to thermal coke) represent the transition
zones between these crystalline structures. In these transitions
zones, the overall pet coke qualities can be a hybrid (or
intermediate) characteristics of the two basic cokes. For example,
a pet coke in the transition zone between sponge coke and needle
coke can take on properties of each or intermediate qualities. This
transition coke can be a higher porosity, sponge coke with
elliptical, unidirectional pores that are interconnected and highly
permeable. This intermediate coke has crystals similar to
honeycomb. On the other hand, localized phenomenon in these
transition zones can override these general rules, and a
combination of the two coke crystalline structures can form in the
same coke drum. For example, a combination of shot coke and sponge
coke can be produced. Likewise, a combination of sponge coke and
needle coke can be produced.
[0641] As noted previously, these transition zones (or crossover
points) between shot, sponge, and needle cokes are not well defined
and are expected to vary with coker feedstocks. That is, the ratio
R (asphaltic coke to thermal coke) is difficult to measure. For a
given coker feed, ratio R can vary for different coker designs and
operating conditions. Consequently, pilot plant data are usually
desirable to determine the types of cokes and transitions zones
derived from specific coker design, operating conditions, and coker
feedstocks. This can be readily accomplished by one skilled in the
art of delayed coking. Typical engineering methods can then be
employed by one skilled in the art to achieve the methods described
in the following sections.
[0642] The internal porosity of petroleum coke varies
substantially. Shot coke, as its name implies, has the consistency
of buck shot with very limited internal porosity (typically
<10%). On the other hand, sponge coke, as its name implies, has
the consistency of sponge or volcanic pumice with significantly
greater internal porosity. The internal porosity of sponge coke can
range from 15%-60+%, depending on coker feedstock characteristics,
coker operating conditions, and coke VCM content. Traditional
sponge coke with 8-12 wt. % VCM is on the lower end of this range.
The modified coke of the current invention (13-25 wt. % VCM)
usually has internal porosity on the upper end of this range. The
internal porosity of froth coke from the coke/foam interface can be
as high as 90%. In contrast, the internal porosity of activated
carbons varies significantly between 30 and 85%, depending on the
carbon source, carbonization process, and activation process. The
internal porosity of petroleum coke normally achieves a maximum
value when the asphaltic to thermal coking is sufficiently low to
initiate the transition from sponge coke to needle coke. In this
transition zone, honeycomb coke maintains a high internal porosity,
but the distribution of pore size can favor larger pores and thus,
undesirable for some adsorption applications. As the crystalline
structure approaches needle coke, the internal porosity decreases
to roughly 10-20%.
[0643] Distribution of pore sizes also varies considerably among
the different types of pet coke crystalline structures. In shot
coke, access to the very limited internal porosity is greatly
inhibited by insufficient pores on the external surface, regardless
of pore size distribution. The pore size distribution of
traditional sponge coke tends to be predominantly macropores.
However, the modified sponge coke of the current invention tends to
have higher percentages of mesopores and micropores, particularly
near the honeycomb coke transition zone. In contrast, the pore size
distribution for commercial activated carbons varies considerably
depending on carbon source, carbonization process, and activation
process. For example, bituminous coals with steam activation
typically have roughly equal distribution of micropores, mesopores,
and macropores.
[0644] (2) Improvement of Pet Coke Carbon Adsorption Character:
[0645] Various methods to modify the coke crystalline structure
have been presented that can promote greater carbon adsorption
qualities. It has been further discovered that certain coker
operations can produce certain types of coke crystalline structure
that have more optimal pet coke adsorption characteristics. In
addition, it has been discovered that the pore size and quantity
can be controlled, to a limited degree, to improve the carbon
adsorption characteristics of the sponge coke crystalline
structure.
[0646] a. Optimal Pet Coke Crystalline Structure:
[0647] Various coker process modifications can be used to produce
pet coke crystalline structures that have more optimal carbon
adsorption characteristics. The theory relating coke crystalline
structure to the coking mechanism ratio R (asphaltic coke/thermal
coke) can be useful to demonstrate this principle. For a given
coker feed, certain ranges of the coking mechanism ratio can be
achieved that produce pet coke crystalline structure with desired
porosity and better carbon adsorption characteristics.
Theoretically, a specific coking mechanism ratio are can be
maintained for a given feed, and produce the type of pet coke
crystalline structure that maximizes carbon adsorption
characteristics (e.g. maximum micropores). For many coker feeds,
this specific coking mechanism ratio R would fall in the transition
zones between sponge coke and needle coke (e.g. honeycomb coke).
However, due to economic constraints, the coking mechanism ratio
can be preferably controlled to produce a sponge coke that has
sufficient adsorption characteristics, but less than this maximum.
This optimal level of carbon adsorption characteristics (previously
described as higher porosity, sponge coke) will depend on various
factors including, but not limited to, (1) size of materials to be
adsorbed, (2) pet coke use & value, and (3) loss & value of
alternative coker products. In this manner, the coke mechanism
ratio can be theoretically used to control the porosity of the
sponge coke, and its inherent carbon adsorption
characteristics.
[0648] In practical applications of this theory, the actual
measurement and determination of the optimal coke mechanism ratio R
(asphaltic coke/thermal coke) are not necessary. As noted
previously, a specific recipe for all refineries is impractical due
to the nature of the delayed coking process and the major
differences in coker feedstocks and process requirements among
various refineries. However, one skilled in the art of delayed
coking can determine the coker conditions required to achieve the
pet coke crystalline structure with the optimal carbon adsorption
characteristics. Coker pilot plant studies can empirically
determine the required coker conditions without undue
experimentation. This is standard practice in the refining
industry. The determination of the optimal pet coke crystalline
structure will require measurement of the carbon adsorption
characteristics relative to the materials to be adsorbed. Also,
effects on coker product yields and their impact on refinery
profitability (LP models) will need to be taken into account on a
case-by-case basis. Initially, the baseline must be established for
a specific refinery's current operations. Incremental deviations
from this baseline can be established for applicable operating
parameters. In most cases, the basic understanding of feedstock
characteristics and coker operating conditions that affect the
coking mechanism ratio (asphaltic coke/thermal coke) should provide
the foundation to fine tune coker conditions. As noted previously,
the thermal coking mechanism is primarily dependent on the coker
operating conditions, but also dependent on the aromatics
concentration of the coker feedstocks. On the other hand, the
asphaltic coking mechanism is primarily dependent on coker
feedstock quality, and limited dependence on coker operating
conditions. In this regard, the impacts of certain coker operating
conditions and coker feedstock modifications are discussed
further.
[0649] Certain coker operating conditions primarily affect the
thermal coking mechanism, but have indirect effects on the
asphaltic coking mechanism, as well. Modifications to coker
operating conditions were previously discussed that modified the
coke crystalline structure. Most of these coker modifications
essentially favored the thermal coking mechanism, and decreased the
coking mechanism ratio R (asphaltic coking/thermal coking).
According to the theory of coking mechanism ratio, the previously
prescribed modifications achieved a coking mechanism ratio that was
primarily sponge coke, and preferably higher porosity, sponge coke
(consistent with the theory's transition zone between sponge coke
and needle coke). The concept of an optimal coking mechanism ratio
is also consistent with achieving sufficient carbon adsorption to
modify fuel properties, while maintaining favorable coker
economics. The coker operating conditions of primary concern are
(1) heater outlet temperature, (2) coke drum pressure, and (3)
recycle rate. The direct and indirect effects of these coker
operating conditions were described previously. The reductions in
the heater outlet temperature reduced both endothermic coking and
cracking reactions. However, its associated reduction in cracking
reactions and drum temperature tend to increase the aromatic
content in the drum. That is, the cracking of heavy aromatics is
normally reduced first by lower temperatures. In most cases, low to
moderate changes in heater outlet temperature has the overall
effect of increasing thermal coking mechanism. In contrast, higher
coke drum pressure and recycle rates tend to increase the thermal
coking mechanism simply by increasing the aromatics concentration
in the coke drum. These coker operation variables also indirectly
affect the asphaltic coking mechanism to the extent that (1) they
decrease aromatics content in the coke drum and/or (2) they
increase the cracking reactions that destabilize the solvent
properties of the oil mixtures. The effects of these operating
variables are discussed previously in greater detail. In addition,
the coking cycle quench of the vapor cracking reactions (the new
independent coker operating variable also discussed earlier in the
first section) can also affect the thermal coking mechanism by
keeping more aromatics in the coke drum. In conclusion, the
previously prescribed modifications to the coker operating
conditions can be used to achieve the optimal coking mechanism
ratio for given coker feedstock in a specific refinery. In this
manner, the optimal coke crystalline structure for sufficient
carbon adsorption characteristics can be maintained for desired
use(s) and process options of the current invention.
[0650] Modifications to the coker feedstock can also be used to
promote the desired carbon adsorption characteristics in the pet
coke. The addition of oils (0.1-99 wt. %; preferably 10 to 50 wt.
%) with high concentrations of aromatics (30-100 wt. %; preferably
>50 wt. %) and low levels of asphaltenes & resins (0.1-15
wt. %; preferably <5 wt. %) can significantly decrease the
coking mechanism ratio, and promote a higher porosity, sponge coke.
For example, aromatic crudes, thermal tars, and coal tars can be
added to the coker feedstock. This would enhance the thermal coking
mechanism and decrease the coking mechanism ratio. In turn, this
would likely increase the porosity of the pet coke and enhance its
carbon adsorption characteristics. Likewise, FCCU slurry
oils/decanted oils could be used in a similar manner. However, the
amount of these highly aromatic FCCU oils recycled to the coker can
be controlled by coker operations via reducing heavy aromatics in
the coker gas oils. In this manner, the FCCU slurry oils/decanted
oils can be productively used to upgrade all of the pet coke to
higher quality and value. In contrast, small cokers, dedicated to
the production of needle coke, have upgraded just these highly
aromatic feedstocks alone.
[0651] In conclusion, the optimal crystalline structure of the base
pet coke can very considerably and depends on many factors, which
include but should not be limited to the following:
[0652] 1. Coker design, operation, & feedstocks: Varies form
refinery to refinery
[0653] 2. Pet coke end-use: Fuel and/or carbon adsorption
applications;
[0654] Varies with application
[0655] 3. Additional Coke Treatment: Additional pore development
and pet coke additives
[0656] As such, the adsorption characteristics of the optimal pet
coke crystalline structure can vary greatly. The internal porosity
of the optimal coke crystalline structure is expected to be in the
range of 30 to 85 wt. %, preferably 50 to 65 wt. %. The pore size
distribution of the optimal pet coke crystalline structure may be
roughly equal distribution of macropores, mesopores, and
micropores. In many applications, a higher distribution of
micropores and mesopores is preferable (e.g. 50% micropores, 30%
mesopores, and 20% macropores). However, greater distribution of
macropores (e.g. 70% macropores, 20% micropores, and 10% mesopores)
can be acceptable for carbon adsorption of some chemical agents for
fuel enhancements. The internal surface area of the optimal pet
coke crystalline structures can vary considerably. However, the
optimal pet coke crystalline structure is expected to provide
surface area of 100 to 1000 square meters per gram; preferably 600
to 1000 square meters per gram. In general, an exemplary pet coke
crystalline structure has greater volumes of mesopores and
micropores than traditional sponge coke. In many applications, the
anisotropic microstructure of the honeycomb coke can be preferable
due to its pore interconnectedness and lower pressure drop
capability. In other applications, the isotropic microstructure of
highly, porous sponge coke (immediately prior to the honeycomb coke
transition zone) can be preferable due to less graphitizable nature
and higher volumes of micropores. In still other applications, a
hybrid microstructure of these two in the transition zone can be
preferable for optimal qualities of both. In still other
applications, a porous coke structure with thick walls and small
pores (sometimes called dense sponge vs. porous sponge) can be
preferable due to its higher density and distribution of
micropores.
[0657] An optimal coke crystalline structure may not only increase
porosity and carbon adsorption character, but can also increase its
susceptibility for further development of pore structure (e.g.
activation). With the exception of needle coke, the lowering of the
coking mechanism ratio R (via changes in process conditions and/or
coker feed changes) usually modifies the coke crystalline structure
in a manner that increases crystal imperfections and/or changes
thermoplastic character of the coke. In fuel-grade, sponge coke,
high sulfur and high metals content already act as impurities in
the crystalline structure, creating an isotropic structure with
numerous pores due to its imperfect crystals. The addition of more
VCMs (i.e. higher hydrogen content and/or lower carbon to hydrogen
ratio) in the current invention further increases the degrees of
crystal imperfections and associated porosity. These properties
already make it less desirable as a graphitizable carbon, and hence
its fuel-grade classification. These imperfections in the
crystalline structure present more reactive sites for activation.
For example, the additional VCMs and their associated hydrogen make
the pet coke less graphitizable and more susceptible to
hydrogenation reactions (i.e. reversible dehydrogenation
reactions). In addition, the cross-linking of the VCMs into the
crystalline structure can also significantly change the pet coke's
thermoplastic character toward thermosetting character. In this
manner, the pet coke behaves more like a char that doesn't go
through a plastic stage with associated realignment of crystallites
and loss of porosity at high temperatures. Similarly, the
anode-grade, sponge coke can be altered via cross-linking of VCMs
into the coke crystalline structure. However, the crystalline
imperfections and the reduction of thermoplastic character are not
as pronounced due to the lower sulfur and metals contents. With
either high-porosity, sponge coke, these modified characteristics
make the modified coke of the current invention more susceptible to
further development of pore structure via activation by traditional
and non-traditional methods.
[0658] b. Physical/Chemical Influences on Pore Development.
[0659] If the pet coke crystalline structure is sponge coke or
sufficiently close to sponge coke (i.e. vs. shot coke), certain
chemical compounds can be added to the coker process and increase
the pet coke porosity. These chemical agents EITHER are low
molecular weight (MW) gases OR release low MW gases/vapors at the
coke drum operating conditions (e.g. cracking reactions). The low
MW gases/vapors would include, but should not be limited to,
H.sub.2, H.sub.2O, NH.sub.3, CH.sub.4, NO, CO, C.sub.2H.sub.6,
CO.sub.2, NO.sub.2, C.sub.3H.sub.8. These low MW gases/vapors can
physically and/or chemically influence the development of pores in
the solidifying coke mass during crystal growth. That is, the low
MW gases/vapors passing upward through the solidifying coke mass
affect the number, shapes, and sizes of the pores in the pet coke.
Overall, these additional low MW gases tend to increase the
quantity of micropores. Similarly, additional higher molecular
weight, hydrocarbon vapors can generally increase the degree of
mesopores, as well. In addition, the injected chemical compounds
can physically or chemically alter crystal growth. The increased
microporosity and total surface area improves the adsorption
qualities of the pet coke, particularly for many gaseous adsorption
applications. The increased mesoporosity improves the adsorption
qualities of the pet coke, particularly for many liquid media
adsorption applications. Furthermore, these injected chemical
compounds can influence the chemical nature of the carbon surfaces,
which effect its adsorption and chemisorption character. For
example, oxygen, nitrogen, and halogen compounds can significantly
alter the adsorption carbon character via the formation of surface
groups and/or complexes. Thus, the addition of these chemical
compounds can substantially modify and increase the carbon
adsorption characteristics of the petroleum coke.
[0660] Various methods to introduce such chemical compounds were
described earlier. The primary purposes of adding these materials
to the coker feedstocks are to (1) enhance carbon adsorption
characteristics of the petroleum coke, (2) enhance coker product
yields, and/or (3) provide recycling of these waste materials
without the need to sort by waste type, particularly plastics. The
following methods are described with greater specificity regarding
(1) injection methods, (2) control of pore number, sizes, &
shapes, and (3) impacts on the coking/cracking reactions.
[0661] b1. Addition of Oxygen-Containing, Carbonaceous
Compounds:
[0662] Promote Sponge Coke (vs. Shot): The addition of
oxygen-containing carbonaceous compounds (i.e. 5-60 wt. % oxygen)
to the coker was discussed previously. This unique application to
the delayed coker (1) produces high porosity, sponge coke (vs. shot
coke), (2) enhances pet coke adsorption characteristics to improve
fuel properties & combustion characteristics, and (3) modifies
pet coke for fuel use. The key aspect of this method was the
production of low molecular weight gases that contained oxygen
(e.g. H.sub.2O, CO, CO.sub.2, CH.sub.4OH) from the cracking of the
added compounds under the coke drum operating conditions. These
oxygen-containing, carbonaceous compounds would include, but should
not be limited to, coals, coal wastes, wood, wood wastes, paper,
and cardboard. In general, these chemical agents are pulverized to
less than 50 mesh and added (e.g. pressurized feed slurry) to the
coker feed, preferably the recycle stream before the fractionator,
and/or most preferably in the combined stream after the
fractionator. The quantity of chemical agents to achieve the
desired effects can range from 0.1-20 wt. %; preferably 5-10 wt.
%.
[0663] b2. Injection of Other Chemical Agents: Cracking Release of
Low MW Gases:
[0664] The current invention also described methods to add other
chemical compounds (including carbonaceous materials without
oxygen) to the delayed coking process that would achieve similar
effects. These chemical compounds were either low-molecular weight
gases or chemical compounds that released low MW gases/vapors into
the coke mass. The low-molecular weight gases can be added to the
bottom of the coke drum during the coking cycle (if inert in the
cracking process) or at the start of the decoking cycle. The
primary examples of these compounds are hydrogen gas (in the
decoking cycle) and various plastics. In a similar manner, rubber
compounds (e.g. scrap rubber) can be added to accomplish these
objectives, as well. In general, these chemical agents are
pulverized to less than 50 mesh and added (e.g. pressurized feed
slurry) to the coker feed, preferably the recycle stream before the
fractionator, and/or most preferably in the combined stream after
the fractionator. The quantity of chemical agents to achieve the
desired effects can range from 0.1-20 wt. %; preferably 5-10 wt. %.
Though an alternative injection of plastics was described earlier,
another exemplary embodiment for plastics/rubber injection is
presented below.
[0665] b3. Direct Injection of Hydrogen or Fuel Gas into the Coke
Mass after the Coking Cycle:
[0666] Direct injection of hydrogen or refinery fuel gas into the
coke mass after the coking cycle can greatly enhance the pet coke's
carbon adsorption characteristics. Though hydrogen may be preferred
due to its effectiveness, refinery fuel gas (e.g. coker off-gas),
particularly with high hydrogen content, can achieve the desired
results with less impact on the fractionator load limits (i.e.
lb-mol/hr.) Hydrogen gas or fuel gas injection into the coke mass
during the coking cycle can prematurely quench the cracking and
coking reactions in the coke drum and defeat the purpose of the
delayed coking process. However, injection of pressurized hydrogen
gas or fuel gas into the solidifying coke mass after the coking
cycle can greatly increase the quantity of mesopores and preferably
micropores in the sponge coke. In addition, hydrogenation of
various reactive hydrocarbons in the modified coke can occur to a
limited degree. This hydrogenation step can produce additional
cracked liquids and increase porosity. In general, hydrogen (of
various purities) can be injected (e.g. with steam) into the bottom
of the drum after the feed has been transferred to the other coke
drum. The quantity of chemical agents to achieve the desired
effects can range from 0.1-20 wt. %; preferably 1-5 wt. %.
[0667] C. Plastics/Rubber Addition to Coker: Exemplary
Embodiment
[0668] Previously, methods were described to add plastics, paper,
cardboard, wood wastes, and/or various other carbonaceous materials
to the delayed coking process. The primary purposes of adding these
materials to the coker feedstocks are to (1) enhance coker product
yields, (2) enhance carbon adsorption characteristics of the
petroleum coke, and/or (3) provide recycling of these waste
materials without the need to sort by waste type, particularly
plastics and rubber compounds. An exemplary embodiment for the
injection of plastics/rubber has been further discovered, and
discussed below. In addition, rubber products that have similar
characteristics (i.e. desirable for the current invention) can also
be recycled as coker feedstock (with or without other plastics).
The addition of certain quantities of other carbonaceous materials
(separately or in combination) in a similar manner can also be
advantageous.
[0669] (1) Unique Use of Extruder/Injection Technologies:
[0670] An exemplary embodiment for the injection of plastics and/or
rubber compounds into the delayed coking process includes a unique
use of extruder and/or injection molding technologies. The primary
purposes of this unique application of extruder technology are to
(1) pulverize mixed plastics/rubber to a uniform size distribution,
(2) gradually melt the plastics/rubber to prevent coking or excess
vaporization, and (3) inject the melted plastic at high pressures
and optimal temperatures to minimize vaporization and provide the
motive force to properly inject the plastics/rubber into the coker
feedstocks.
[0671] First, an appropriate pulverizer must be selected to
pulverize various plastics/rubber of various shapes and sizes to
pellet size or smaller (2 to 100 mesh; preferably 50 to 100 mesh),
depending on extruder feed specification requirements. A
conventional or commercially available vortex shredder and/or soft
solids pulverizer with size classifiers can provide adequate
pulverization. However, the chosen pulverization system must
address concerns of high temperatures and potential plugging. One
skilled in the art of solids handling and pulverization can select
(or design) the pulverization system(s) to achieve these
objectives.
[0672] Next, the proper extruder/injection system must be selected
(and modified) or engineered to (1) gradually heat & melt the
plastics/rubber, (2) pressurize the molten plastics/rubber, and (3)
inject into the delayed coker, similar to rubber extrusion.
Multiple extruders may be necessary to achieve the flow rate
required for a given coker application. Gradually heating the
plastics/rubber at controlled temperatures in a pressurized system
is critical to prevent coking and limit vaporization. Preferably,
the controlled temperature increases should not exceed 10 degrees
Centigrade per minute. The maximum temperature at injection should
be significantly below (5-30.degree. F.; preferably 10-20.degree.
F.) (1) the coking temperatures of the plastics/rubber of concern,
and/or (2) vaporization temperatures of >80% of the
plastics/rubber, preferably >90%. The pressure of the extruder
will depend on various factors, including (but not limited to) flow
rate considerations, vaporization characteristics of the
plastics/rubber, and pressure requirements of the delayed coker
injection point. The temperature of the plastics/rubber at the
point of injection may be significantly less than the temperature
of the coker feedstock. Consequently, the heater outlet temperature
must be adjusted to achieve the desired drum temperature after the
plastics/rubber are added. Depending on coker process requirements
and the quantities and properties of the plastics/rubber, one
skilled in the art can make the appropriate modifications for each
application via engineering calculations and minor tests, if
necessary. In general, the various plastics and/or rubber compounds
are pulverized and added to the extruder injection system. The
molten plastics/rubber compounds are injected into the coker feed,
the recycle stream before the fractionator, and/or most preferably
in the combined stream after the fractionator. The quantity of
recycled plastics and/or rubber compounds to achieve the desired
effects can range from 0.1-30 wt. %; preferably 5-15 wt. %.
Conceivably, other pulverized carbonaceous materials could be added
to the extruder/injection system (e.g. plastics/paper slurry).
However, the quantity of these materials would limited by the
extruder injector design.
[0673] D. Coke Hydroprocessinq in Coke Drums
[0674] As previously discussed, various coker process modifications
can alter pet coke crystalline structure, preferably sponge coke
with higher porosity and improved carbon adsorption
characteristics. Additional coker process modifications have been
discovered to improve pet coke properties via low-severity,
hydroprocessing of the petroleum coke.
[0675] (1) Prior Art: Hydroprocessing of Petroleum Products:
[0676] Hydrogenation, one of the oldest catalytic processes, is the
primary component of a group of various petroleum upgrading
processes, generally called hydroprocessing. Hydrocracking is a
type of hydroprocessing that combines hydrogenation with catalytic
cracking. Hydrotreating is another class of hydroprocessing
technologies that selectively treat and remove certain impurities
via catalytic hydrogenation. Hydroprocessing technologies for
residuals typically use catalytic hydrogenation to remove
impurities (similar to hydrotreating) followed by the combination
of catalytic hydrogenation and catalytic cracking (similar to
hydrocracking).
[0677] a. Prior Art; Hydrocracking of Gas Oils & Middle
Distillates:
[0678] The hydrocracking process was originally developed for
upgrading petroleum feedstocks in the early 1930s. Hydrocracking
combines catalytic cracking (e.g. scission of carbon-carbon single
bonds) with catalytic hydrogenation (e.g. hydrogen addition to
carbon-carbon double bonds). In this process, complementary
reaction mechanisms occur; endothermic cracking provides olefins
and aromatics for hydrogenation, while exothermic hydrogenation
provides excess heat for cracking and temperature increases, if
desirable.
[0679] Most hydrocracking catalysts normally consist of
silica-alumina base impregnated with a rare earth metal (e.g.
platinum, palladium, & nickel). The silica-alumina promotes
cracking activity, while the rare earth promotes hydrogenation.
Typically, the catalyst is selective with respect to less
production of propane and lighter versus normal cracking processes.
This catalyst selectivity reduces with age, producing more gas at
the end of run, requiring higher temperatures to maintain
conversion. The catalyst activity also decreases over time with the
accumulation of coke and other deposits, requiring regeneration
above certain threshold levels. The circulation of large quantities
of hydrogen with the feedstock usually inhibits catalyst fouling.
In addition, hydrocracking catalysts are susceptible to poisoning
by metallic salts, oxygen, organic nitrogen and sulfur in the
feedstocks. Consequently, the feedstocks are often hydrotreated
either internally (i.e. guard reactor) or externally (see
hydrotreating below) to remove sulfur, nitrogen, oxygen, and
metals, while saturating feedstock olefins. Compositions of
hydrocracking catalysts are normally tailored to the process,
feeds, and desired products.
[0680] The hydrocracking process is typically a fixed-bed,
regenerative process, with one or two stages of reactors. Each
reactor normally has several beds of catalyst to allow injection of
cold, recycled hydrogen for temperature control. Hydrogen-rich gas
is usually mixed with the feed prior to the feed heater. The
two-phase fluid from the heater outlet typically flows downward
through the reactors. The hydrogen-rich gas in the reactor effluent
is separated form the oil products and recycled with hydrogen
makeup to be mixed with feed at the heater inlet. Operating
conditions in the reactor(s) range from 500 to 800 OF and 1000 to
2000 psig. The temperature and pressure vary with the age &
type of catalyst, the products desired, and the properties of the
feedstocks. The primary operating variables are reactor
temperature, reactor pressure, space velocity, and detrimental
composition of the feed (i.e. contents of sulfur, oxygen, organic
nitrogen, metals, & heavy polynuclear aromatics). The severity
of the hydrocracking process is measured by the degree of
conversion of the feed to lighter products. Typically, the net
result of hydrocracking is 40 to 50 wt. % conversion of high
boiling feedstocks to saturated cracked liquids with substantially
lower boiling points (e.g. <400.degree. F.). Hydrocracking also
increases volumetric yields up to 125%.
[0681] b. Prior Art; Hydrotreating of Gas Oils & Middle
Distillates:
[0682] Hydrotreating refers to a class of hydroprocessing processes
that catalytically stabilize petroleum products and/or remove
objectionable components in products or feedstocks via catalytic
hydrogenation. Stabilization usually involves converting
unsaturated hydrocarbons (e.g. olefins and unstable, gum-forming
diolefins) to paraffins. Objectionable components removed by
hydrotreating include sulfur, nitrogen, oxygen, certain halides,
trace metals, and aromatic compounds. Hydrotreating processes
employed for removal of a specific component include
hydrodesulfurization (HDS), hydrodenitrification (HDN), and
hydrodemetallization (HDM). Hydrotreating processes are applied to
a wide range of feedstocks, from naphtha to reduced crude. Unlike
hydrocracking, the lower severity hydrotreating processes tend to
inhibit cracking and to promote more selectivity.
[0683] Hydrotreating catalysts, particularly those for removal of a
specific component, tend to be more sophisticated than
hydrocracking catalysts. Cobalt and molybdenum oxides on alumina
catalysts are generally used due to their high selectivity,
resistance to poisons, and ease of regeneration. Cobalt-molybdenum
catalysts are more selective to sulfur compounds. Nickel-molybdenum
catalysts have higher hydrogenation activity. Thus, they are
preferable for nitrogen removal and saturation of aromatic rings.
Other types of hydrotreating catalysts include nickel oxide, nickel
thiomolybdate, tungsten sulfides, nickel sulfides, and vanadium
oxide. In many applications, the catalysts must be activated by
converting the hydrogenation metals from the oxide to the sulfide
form. Also, catalyst pore size is typically adjusted to improve and
maintain catalyst activity throughout the run cycle between
regenerations.
[0684] Similar to hydrocracking, the hydrotreating processes
typically are a fixed-bed, regenerative process, but often have a
single reactor stage. The oil feed is usually mixed with
hydrogen-rich gas before being heated to the reactor inlet
temperature: normally <800.degree. F. to minimize cracking. As
with hydrocracking, a hydrogen-rich gas is separated from the oil
products and typically recycled with makeup hydrogen back to be
mixed with feed at the heater inlet. Operating conditions in the
reactor range from 600 to 800.degree. F. and 100 to 3000 psig. The
space velocity (LHSV) ranges from 1.5 to 8.0. The temperature,
pressure, space velocity and hydrogen consumption vary with the age
& type of catalyst, the desired feedstock improvements, and the
properties of the feedstocks. Typically, hydrogen consumption is as
follows:
3 Sulfur Removal 70 scf/bbl of feed for each wt. % sulfur Nitrogen
Removal 320 scf/bbl of feed for each wt. % nitrogen Oxygen Removal
180 scf/bbl of feed for each wt. % oxygen Aromatics/Olefins
Reduction Stoichiometric amount based on relative types
[0685] If operating conditions cause significant cracking, the
hydrogen consumption increases rapidly. Actual hydrogen makeup
requirements are 2 to 10 times the stoichiometric hydrogen required
due to solubility loss in the oil products leaving the reactor and
saturation of olefins produced by cracking. Hydrogen recycle is
typically 2000 scf/bbl of feed to maintain sufficient hydrogen
partial pressures. All reactions are exothermic. Depending on
specific conditions, a temperature rise through the reactor of 5 to
20.degree. F. usually occurs.
[0686] The primary operating variables of hydrotreating processes
are reactor temperature, hydrogen partial pressure, and space
velocity. Increasing temperature and hydrogen partial pressure
increases desired component removal and hydrogen consumption.
Increasing pressure also increases hydrogen saturation and reduces
coke formation. Increasing space velocity reduces conversion,
hydrogen consumption, and coke formation. The severity of the
hydrotreating process is measured by the degree of conversion or
removal of targeted feed components. Typically, the net result of
many hydrotreating processes is the conversion of undesirable feed
components to <10 wt. %. Furthermore, volumetric yields do not
normally change to any significant degree, since the boiling points
of the oil products are essentially the same as the feedstocks.
That is, the boiling range of hydrotreated feedstocks does not
change dramatically.
[0687] c. Prior Art; Hydroprocessing of Residuals:
[0688] In the last 20 years, numerous hydroprocessing technologies
have been developed to prepare residual feedstocks for cracking and
coking units. Atmospheric distillation tower bottoms, often called
atmospheric reduced crudes or ARCs, are the primary feedstocks. The
primary purposes of these hydroprocessing technologies are to
reduce the boiling range of the feedstocks and/or remove
substantial amounts of impurities, including metals, sulfur,
nitrogen, and high carbon-forming compounds. Many of these
hydroprocessing technologies are capable of 25 to 65% feed
conversion rates. Common industry terminology for classes of these
hydroprocessing technologies also include hydroconversion,
hydrorefining, and resid hydrodesulfurization (HDS). Trade names
for specific processes include Residfining, ARDS, VRDS, H-Oil, and
LC-fining.
[0689] In general, these hydroprocessing technologies have similar
process flow schemes and employ various types of catalytic
reactors: fixed-bed, ebullated bed, or expanded bed. The latter two
refer to a catalyst bed fluidized by a combination of gases and/or
liquids. Typically, a guard reactor is followed by a series of
hydroprocessing reactors. The guard reactor normally reduces the
metals content and the carbon-forming potential of the feed. The
hydroprocessing reactors are operated to remove sulfur and nitrogen
and crack the 1050.degree. F+materials to lower boiling points. The
reactors are designed for very low space velocities of 0.2 to 0.5
v/hr/v, limiting process flow rates. Operating conditions in the
reactors vary, but are typically maintained with inlet temperatures
between 800 and 850.degree. F. and pressures in the range of 2000
to 3000 psig.
[0690] The catalysts in these hydroprocessing technologies can vary
significantly among technologies and applications of the same
technology. The guard reactor catalyst is typically a
silica-alumina catalyst with large pore size (150-200 A.degree.)
and low loading of hydrogenation metals (e.g. cobalt and
molybdenum). The catalysts for the other reactors are tailor-made
for the feedstock and conversion level desired. These catalysts
generally have a wide range of particle sizes, various catalytic
metal loadings and types. Pore sizes usually range from 80to
100A.degree..
[0691] (2) Present Invention: Hydroprocessing of Petroleum
Coke:
[0692] In the context of the current invention, hydroprocessing of
petroleum coke refers to any process that uses hydrogen and/or
catalyst(s) at sufficient temperature and pressure to (1) reduce
the quantity of coke via various types of hydrogenation and/or
cracking of coke mass, (2) modify and/or improve coke crystalline
structure & adsorption character, and/or (3) remove substantial
amounts of impurities, including sulfur, nitrogen, metals, and high
carbon-forming compounds. This hydroprocessing of the petroleum
coke can be processes similar to hydrocracking, hydrotreating, and
hydroprocessing of residuals in the prior art (described
above).
[0693] Petroleum coke hydroprocessing can be done separately from
the coking process, but preferably within the coking process. That
is, hydrogen can be injected into coke drums at the beginning of
decoking cycles to initiate hydroprocessing of the pet coke in the
coke drums. In addition, the petroleum coke does not necessarily
have to be the modified pet coke of the current invention. Though
the modified pet coke can provide advantageous catalyst properties,
other catalysts can be used instead or in addition. Preferably,
this hydroprocessing can be done in the presence of inexpensive
catalysts, if needed. A carrier fluid (liquid and/or gas) can also
be used to improve reactivity and overall benefits. Primary
purposes for coke hydroprocessing include:
[0694] 1. Reduce overall process coke yield via cracking &
hydrogenation of coke compounds,
[0695] 2. Reduce sulfur, nitrogen, and/or metals (V, Ni, etc.)
contents of petroleum coke,
[0696] 3. Reduce coke yield & improve coke qualities via
optimized coke formation,
[0697] 4. Improve carbon adsorption character; approaching
activated carbon, and/or
[0698] 5. Provide additional hydrotreating/hydrocracking capacity
for middle distillates.
[0699] High severity hydroprocessing of the prior art is not
necessarily required to achieve these objectives due to (1) lower
conversion requirements, (2) higher residence time, and (3) less
liquid reactants. First, high conversion of the pet coke to cracked
liquids is not necessary for successful pet coke hydroprocessing.
Incremental improvements are normally sufficient to achieve
desirable benefits in most refineries. That is, each ten-percent
conversion in the coke hydroprocessing represents roughly 2.5 to
4.0% reductions in overall coke yield, depending on coker feed
quality. Thus, <10-15 wt. % conversion (vs. 25-65+wt. %) of coke
mass to cracked liquids can be sufficient to justify coke
hydroprocessing, particularly within the delayed coking process.
However, greater conversions (e.g. 25-45%) can be more desirable to
further reduce overall coke yield and produce pet coke with
superior carbon adsorption with much higher value. On the other
hand, too much conversion can be detrimental to the modified pet
coke crystalline structure and suboptimal. Secondly, high
reactivity (e.g. fast reaction rates or strong reaction kinetics)
and high selectivity are not required for the pet coke
hydroprocessing either. This is particularly true if a third coke
drum is added to increase available coke cycle time and thus,
hydroprocessing residence time. Thirdly, the system pressure
requirements are typically less due to significantly less liquid
character of the desired reactants. The mechanisms of hydrogen
transfer with less liquid character can significantly reduce the
required hydrogen partial pressure. Furthermore, the reduced liquid
character of the reactants provides higher hydrogen partial
pressure at the same system pressures. Consequently, coke
hydroprocessing can normally be successful with lower quality
catalysts and lower severity of operating conditions (e.g. much
lower hydrogen partial pressure) versus hydroprocessing of the
prior art (e.g. hydrotreating, hydrocracking, & hydroprocessing
of residuals).
[0700] a. Reaction Vessels:
[0701] The hydroprocessing of pet coke can be carried out in
various types of reaction vessels. New or existing coke drums in
traditional pairs of two can be sufficient reaction vessels for pet
coke hydroprocessing. Alternatively, new reaction vessels separate
form the delayed coking process can also be used. Preferably, new
coke drums in series of three (vs. traditional pairs of 2) would
provide additional advantages.
[0702] In some cases, existing or new coke drums in the current
delayed coking process can be sufficient reaction vessels for pet
coke hydroprocessing. The semi-continuous, delayed coking process
normally has pairs of coke drums with 2 cycles (coking &
decoking). These issues were briefly described in earlier sections.
The coke mass in the coke drum at the end of the coking cycle is
already at or above the desired temperature (500 to 850.degree. F;
preferably 700 to 800.degree. F.) for pet coke hydroprocessing.
Hydrogen and catalyst can be added as needed, before, during, or
after some initial coke cooling (if it is desirable). In addition,
traditional coking cycles can be modified to provide sufficient
time for some pet coke hydroprocessing. However, this option is
often suboptimal due to current constraints in cycle times and
equipment. Limited residence time for pet coke hydroprocessing can
require faster reaction rates, limit pet coke hydroprocessing
conversion, and reduce delayed coker throughputs. Faster reaction
rates can require higher hydrogen partial (and process) pressures.
The current coke drums are often pressure limited (e.g. 100 psig)
due to current metallurgy, delayed coker thermal cycles, and
typical design parameters (e.g. head seals). New coke drums can
alleviate the pressure limitations, but have limited effect on time
constraints.
[0703] In some cases, separate reaction vessels may be desirable to
remove process pressure limitations and time constraints. These
separate reaction vessels can be within or outside the current
delayed coker process boundaries. In most applications, pet coke
hydroprocessing reaction vessels, that are not integrated into the
delayed coking process, are not usually practical due to excessive
capital and operating costs. The design challenge and fuel costs
are often prohibitive for cooling the coke, removing it from the
coke drums, transferring to other reaction vessels, and reheating
the pet coke. Consequently, this option is not advantageous in most
cases.
[0704] In many applications of this technology, the addition of a
3rd coke drum with a third operating cycle may be the desired
embodiment. The third coke drum in the series provides a third
operating cycle in the delayed coker: coke treatment (or
hydroprocessing) cycle. That is, pet coke hydroprocessing (and/or
other treatment options described later) is integrated into the
delayed coking process. This third coker cycle can allow
substantially more residence time for the hydroprocessing
reactions, potentially reducing the required operating severity for
a desired hydroprocessing conversion. In addition, part of the
cooling in the traditional decoking cycle can be integrated into
the pet coke hydroprocessing cycle, reduce overall coker cycle
time, and increase coker throughput capacity. For example, delayed
coker cycles (coking, coke treatment, and decoking cycles) could be
reduced to lowest practical cycle times: 12-14 hours each. New coke
drums (with or without new materials technologies) and better
mechanical seals can allow higher operating pressures even with
thermal cycles, structural stresses, and consistent seal
requirements. As discussed previously, new coke drums would also
provide the opportunity to implement advanced design features,
including (1) modified drill stem & top head seals for the
addition of chemical and/or thermal quenching agents during the
coking cycle to prevent vapors overcracking and (2) modified bottom
head & skirting to remove coke in larger chunks for
low-pressure drop applications of adsorption carbon (e.g. utility
boilers).
[0705] A basic process flow diagram for a delayed coker with three
coke drums is shown in FIG. 8. The delayed coking process equipment
for this embodiment of the present invention is similar to the
prior art, with the addition of a third parallel coke drum.
However, the operation, as discussed below, is substantially
different. This embodiment of the current invention adds a third
process cycle as well as a third parallel coke drum. The modified
delayed coking is still a semi-continuous process, but has three
parallel coke drums that alternate between coking, coke treatment,
and decoking cycles. The coke quench is completed in the treatment
and/or decoking cycles. That is, the coke quench can be partially
completed at the end of the coke treatment cycle and finished at
the beginning of the decoking cycle to minimize and/or optimize
coker cycle times.
[0706] In the coking cycle, coker feedstock is heated and
transferred to the coke drum until full. Hot residua feed 810 is
introduced into the bottom of a coker fractionator 812, where it
combines with condensed recycle. This mixture 814 is pumped through
a coker heater 816, where the desired coking temperature (normally
between 900.degree. F. and 950.degree. F.) is achieved, causing
partial vaporization and mild cracking. Steam or boiler feedwater
818 is often injected into the heater tubes to prevent the coking
of feed in the furnace. Typically, the heater outlet temperature is
controlled by a temperature gauge 820 that sends a signal to a
control valve 822 to regulate the amount of fuel 824 to the heater.
A vapor-liquid mixture 826 exits the heater, and a 3-way control
valve 827 diverts it to a coking drum 828. Sufficient residence
time is provided in the coking drum to allow the thermal cracking
and coking reactions to proceed. By design, the coking reactions
are "delayed" until the heater charge reaches the coke drums. In
this manner, the vapor-liquid mixture is thermally cracked in the
drum to produce lighter hydrocarbons, which vaporize and exit the
coke drum. A control valve mechanism 829 is used to direct the
outflows of the respective coke drums and control system pressure
(e.g. particularly during coke drum switching). The drum vapor line
temperature 830 (i.e. temperature of the vapors leaving the coke
drum) is the measured parameter used to represent the average drum
temperature. Petroleum coke and some residuals (e.g. cracked
hydrocarbons) remain in the coke drum. When the coking drum is
sufficiently full of coke, the coking cycle ends. The heater outlet
charge is then switched from the first coke drum to a parallel coke
drum to initiate its coking cycle. Meanwhile, the treatment cycle
begins in the first coke drum.
[0707] In the coke treatment cycle of the current invention, the
petroleum coke undergoes one or more of the various treatment
options (e.g. hydroprocessing, coke extraction, chemical
activation, etc.). Coke quench can be initiated during the
treatment cycle. Quench media (e.g. steam) can be used at the
beginning of the treatment cycle to cool the coke drum to the
optimal treatment temperature. Treatment agents (e.g. hydrogen
& catalyst) can be injected into the drum at various injection
locations 831, 832, and/or 834. After the coke treatment (e.g. coke
hydroprocessing) is completed, additional quench can be achieved,
if cycle time permits. As described below, quench media can be
injected at various locations: 831, 832, and/or 834. After the
treatment cycle is completed, the coke drum passes (e.g. sometimes
directly) into the decoking cycle.
[0708] In the decoking cycle, the coke drum and its contents are
further cooled, the coke is drilled from the drum, and the coking
drum is prepared for the next coking cycle. Cooling the coke
normally occurs in three distinct stages. In the first stage, the
coke is cooled and stripped by steam or other stripping media 831
to economically maximize the removal of recoverable hydrocarbons
entrained or otherwise remaining in the coke. This first stage is
optional, its degree of use depending on the desired coke VCM
content. In the second stage of cooling, water or other cooling
media 832 is injected to reduce the drum temperature while avoiding
thermal shock to the coke drum. Vaporized water from this cooling
media further promotes the removal of additional vaporizable
hydrocarbons. In the final cooling stage, the drum is quenched by
water or other quenching media 834 to rapidly lower the drum
temperatures to conditions favorable for safe coke removal. After
the quenching is complete, the bottom and top heads of the drum are
removed. The petroleum coke 836 is then cut, typically by hydraulic
water jet, and removed from the drum. After coke removal, the
drumheads are replaced, the drum is preheated, and otherwise
readied for the next coking cycle.
[0709] Lighter hydrocarbons 838 are vaporized, removed overhead
from the coking drums (primarily in the coking cycle), and
transferred to a coker fractionator 812, where they are separated
and recovered. Coker heavy gas oil (HGO) 840 and coker light gas
oil (LGO) 842 are drawn off the fractionator at the desired boiling
temperature ranges: HGO: roughly 650-870.degree. F; LGO: roughly
400-650.degree. F. The fractionator overhead stream, coker wet gas
844, goes to a separator 846, where it is separated into dry gas
848, water 850, and unstable naphtha 852. A reflux fraction 854 is
often returned to the fractionator.
[0710] b. Theory of Operation:
[0711] In general, hydroprocessing of petroleum coke combines
hydrogenation and cracking reactions with or without catalytic
activation. Overall, this hydroprocessing has complex reaction
chemistry due to the complex nature of the chemical compounds and
catalysts involved. That is, numerous complementary and competing
chemical reactions take place in pet coke hydroprocessing. The
primary reaction mechanisms in typical applications are described
as part of a simplified theory of operation. However, this theory
of operation may not accurately describe all applications, and
should not limit the current invention. Hydrogenation and various
cracking mechanisms (e.g. thermal, catalytic, & hydrogenolysis)
are generally discussed, along with their interaction in this
process. The impacts of key operational parameters (e.g. system
temperature, catalyst activity, hydrogen partial pressure, and
residence time) are also discussed.
[0712] At the end of the coking cycle in the delayed coking
process, the petroleum coke is normally a semi-solid (or
semi-liquid) coke mass. That is, much of the coke mass at
temperatures of 800 to 900.degree. F. and pressures >25 psig has
solidified crystalline growth from thermal cracking in the absence
of hydrogen. This pet coke crystalline growth is caused by various
reactions: including dehydrogenation, condensation,
oligomerization, aromatization, polymerization, and/or
cross-linking of heavy compounds in the coking cycle. However, some
materials remain a heavy, pitch-like liquid, until cooled further.
These pitch-like materials are expected to be primarily asphaltenes
with some resins and other heavy aromatics. These materials are
usually solutized, but not yet chemically/physically attached to
the coke crystalline structure. Higher coke crystalline contents
(e.g. lower asphaltenes/resins to aromatics ratio) are more
favorable for coke hydroprocessing due to greater adsorption and
catalytic properties within its substantial levels of porous, solid
coke at these conditions. At lower temperatures, a greater portion
of coke mass can become solid crystals with more favorable
adsorption and catalytic properties.
[0713] As noted previously, less graphitizable carbon structures
are often more susceptible to hydrogenation reactions (i.e.
reversible dehydrogenation reactions) than anode-grade, sponge
coke. The degree of the non-graphitizable carbon character
apparently depends on the degree of mesophase transition in the
coking process. In turn, this degree of mesophase transition
greatly depends on the chemical composition of the coker feedstocks
and the coker operating conditions, particularly temperature
profiles. The modified pet coke of the current invention (discussed
previously) is the desired embodiment for this hydroprocessing
treatment due to its less graphitizable character. However, a
carbonaceous material with even less graphitizable character can be
preferable under certain conditions. For example, a porous,
carbonaceous material (e.g. semicoke) intermediate between
mesophase pitch and a non-deformable green coke can be more
susceptible to the hydrogenation reactions of this coke
hydroprocessing. Conceivably, this embodiment would optimize coker
feeds and operating conditions to obtain the carbonaceous material
with the lowest carbon to hydrogen ratio (C/H), while maintaining a
porous, crystalline structure (vs. pitch-like materials).
[0714] b1. Hydrogenation:
[0715] The addition of hydrogen to this semi-solid, coke mass will
normally initiate some degree of hydrogenation of olefinic,
aromatic, and/or heterocyclic compounds in the coke mass.
Hydrogenation is generally a class of reactions that breaks double
bonds and saturates the reactant (e.g. multi-ring aromatics) with
hydrogen. The hydrogenation reaction mechanism usually follows
free-radical chain reactions, where free-radicals are highly
reactive intermediates which have an unpaired electron. In
hydrogenation, the free-radical is typically atomic hydrogen (vs.
molecular hydrogen H.sub.2). The porous pet coke in the semi-solid
coke mass has a strong tendency to break molecular hydrogen into
atomic hydrogen with an unpaired electron. That is, adsorption of
hydrogen on the pet coke's internal surface catalytically promotes
the breakdown of molecular hydrogen (bond energy: 103 kcal/mole)
into hydrogen free-radicals. A similar reaction mechanism was
discussed previously for the breakdown of molecular oxygen (bond
energy: 117 kcal/mole) in the use of activated carbons or modified
pet cokes as an oxidation catalyst. In this manner, hydrogen
free-radicals are readily available and migrate on the surface of
the pet coke, which is also the desired reactant in the
hydrogenation. The degree of pet coke hydrogenation depends on
various factors, including (1) coke mass composition, (2) catalyst
activity, (3) temperature, (4) hydrogen partial pressure, and (5)
residence time.
[0716] Residence time discussion: 0.5 to 12 hours vs. residence
times usually <1.0 hour. Thus, reaction rate is not as critical
as long as sufficient equilibrium driving force is present for
reactions to occur. Excess hydrogen will tend to drive equilibrium
in favor of hydrogenation.
[0717] The composition and reactivity of the semi-solid, coke mass
can have substantial impact on the degree of pet coke
hydrogenation. As noted above, the pet coke mass typically consists
of polyaromatics, resins, and asphaltenes. As such, the primary
focus of this discussion will be the hydrogenation of aromatic
compounds. The resonance stabilization energy of most aromatic
bonds renders them unbreakable at process temperatures
<1100.degree. F. until the aromatic character is destroyed by
hydrogenation. Limited hydrogenation occurs in the delayed coking
process due to lack of hydrogen and hydrogenation catalysts. As a
result, these aromatic compounds are concentrated in the coke mass
from dehydrogenation and coking reactions. In contrast, the
hydroprocessing of pet coke promotes the hydrogenation and
subsequent cracking of these polyaromatic compounds. The
hydrogenation reaction is more thermodynamically favorable for
compounds with greater number of rings and irregularity (e.g. less
symmetry) in the aromatic clusters. That is, hydrogenation is
favored in polyaromatics with lower average resonance energy per
bond or weaker bonds. Thus, the asphaltenes and resins in the
pitch-like materials are normally more likely to undergo
hydrogenation than the polyaromatics in the crystallized coke due
to weaker bonds, as evidenced by its more liquid character (e.g.
lower melting point). If predominant hydrogenation of the
asphaltenes and resins occurs with subsequent cracking, the lower
asphaltenes/resins to aromatics ratio will create a more highly
porous, sponge coke. Consequently, the coke mass catalyst activity
will increase as the asphaltenes and resins are hydrogenated and
cracked. Ultimately, the hydroprocessing of the pet coke will
provide even better coke crystalline structure with greater
adsorption character.
[0718] Since hydrogenation and dehydrogenation are reversible
reactions, the excess concentrations of hydrogen and aromatic
compounds in pet coke hydroprocessing tend to drive the reaction
strongly in favor of hydrogenation.
[0719] Hydrogenation reactions are not too sensitive to temperature
within the considered temperature ranges of pet coke
hydroprocessing: 500-1000.degree. F (preferably 700-800.degree.
F.). Hydrogenation is an exothermic reaction, and equilibrium
yields are favored by relatively low temperatures. However,
reaction rates increase with temperature. Hydrogenation of
polyaromatic compounds becomes a compromise between using low
temperatures to achieve maximum reduction of aromatic content and
high temperatures to provide high reaction rates and minimize
catalyst charge per barrel of feed. Maximum aromatic reduction is
normally achieved between 700.degree. F. and 750.degree. F. due to
the interrelation of thermodynamic equilibrium and reaction rates.
However, higher reaction rates and associated high temperatures are
less important with ample residence time. Thus, lower temperatures
can also provide desirable conversion levels with longer residence
times. Furthermore, lower temperatures would solidify more of the
coke mass, which can provide more favorable adsorption and
catalytic characteristics. Thus, coke hydroprocessing objectives
and the coke mass composition & physical condition play a
significant role in determining the optimal temperature. In
general, the optimum temperature, for a given pressure, is a
function of the types of aromatic compounds in the coke mass,
residence time, hydrogen concentration, and catalyst considerations
(e.g. amount & cost).
[0720] Increasing the hydrogen partial pressure generally increases
the degree of hydrogenation reactions. As discussed in the prior
art, the reaction kinetics of hydrogenation reactions is more
favorable with higher hydrogen partial pressure. In fact, hydrogen
partial pressure is the most important parameter controlling
traditional aromatic saturation. Traditional hydroprocessing (e.g.
hydrocracking & hydrotreating) relies heavily on very high
hydrogen partial pressures to create fast and effective transfer of
hydrogen from the gas phase to the liquid phase of the reactants.
That is, the high hydrogen partial pressure promotes hydrogen
free-radicals in the liquid phase via various mechanisms, including
hydrogen solubility, aromatic solvents and cycles of hydrogenation
& dehydrogenation. In contrast, the hydroprocessing of pet coke
behaves more like solid-gas phase reactions, more similar to
adsorption processes. Molecular hydrogen is typically adsorbed by
the porous coke in the coke mass and catalytically converted to
hydrogen free-radicals. The carbon adsorption character (e.g. Van
der Waal forces) of the pet coke mass allow the relatively
unrestrained migration of hydrogen free-radicals. That is, hydrogen
access to the polyaromatic compounds in the coke mass is less
inhibited by excess liquid flow of feed in the prior art. In other
words, the primary reactants (coke mass) in the hydroprocessing of
pet coke are in a semi-solid state that does not fill the voids of
the reaction vessel with a free flowing liquid. Hence, the hydrogen
free-radical transfer mechanism of the pet coke hydroprocessing is
substantially less dependent on the hydrogen partial pressure.
Also, the hydrogen has a significantly higher molar concentration,
since it is the primary fluid that causes the increased system
pressure. Thus, the partial pressure of hydrogen required can be
achieved at lower system pressures versus the prior art for
hydroconversion processes. Furthermore, longer residence times in
the current invention (discussed later) further reduce the need for
fast hydrogen transfer mechanisms (vs. prior art), and require even
less hydrogen partial pressure. Finally, the lower conversion
requirements for acceptable operation also reduces the need for the
high hydrogen partial pressures of the prior art. In many cases,
the highest practical system pressure may be desired to increase
hydrogen partial pressure, but not necessarily required to aftain
sufficient hydrogen transfer in pet coke hydroprocessing.
[0721] In many cases, the hydrogenation catalyst activity of the
porous, sponge coke in the coke mass is sufficient to initiate
hydrogenation of the asphaltenes, resins, and other polyaromatics
in the coke mass. However, in some cases, other catalysts or
additives with additional hydrogenation catalytic activity may be
necessary to cause sufficient hydrogenation initially. The primary
role of other catalysts or additives would be to enhance the
formation and transfer of hydrogen free-radicals and inhibit
dehydrogenation & coking reactions. Good hydrogenation
catalysts tend to be acidic, and are susceptible to poisoning,
particularly with nitrogen. A variety of transition metals (e.g.
iron, nickel, cobalt, molybdenum, tin, & tungsten) provide
favorable hydrogenation catalyst characteristics in this process
environment. That is, these metals are reactive in the sulfide
form, as well as the metallic state. Traditional hydrogenation
catalysts (e.g. Co/Mo and Ni/Mo) can be technically feasible for
pet coke hydroprocessing (e.g. can be impregnated on the coke), but
would likely be too costly as a non-recoverable coke additive. More
likely, iron compounds would be used as powdered or impregnated
additives, due to their very low costs. For example, iron oxide
will likely be converted in-situ to the sulfide form, and promote
hydrogen transfer reactions. Iron sulfate is also an effective
additive. In some cases, minor additions of iron sulfate may be
desirable to initiate hydrogenation reactions, until sufficient
sulfur is generated from the coke mass to react with predominate
iron oxide additives. The injection of these catalyst/additives can
be achieved by various means. For example, finely powdered
additives can be added to the coke during the coking cycle or
injected in to the coke with hydrogen or steam at the beginning of
the pet coke hydroprocessing. In many cases, finely powdered
additives can be preferably added via a cooling media, such as used
lubricating oils or heavy gas oils, that vaporize (e.g.
>700.degree. F.) and distributes the additives in the coke mass
in a fairly uniform manner.
[0722] Hydrogen circulation rates are typically 3-4 times the
stoichiometric amount of hydrogen consumption. Hydrogen sulfide
concentrations tend to inhibit hydrogenation of aromatic rings and
ammonia tends to decrease hydrocracking conversion. Therefore,
continual removal of ammonia and hydrogen sulfide via continual
mass transfer away from coke mass reaction sites is preferable. For
example,
[0723] b2. Cracking Reactions:
[0724] Various cracking reactions are complementary to the
hydrogenation reactions. That is, the exothermic hydrogenation
reactions (1) usually provide more than enough heat for the
endothermic cracking reactions, and/or (2) produce intermediate
compounds that are more readily cracked. In the latter, the
resonance stabilization of many aromatic bonds renders them
unbreakable at normal process temperatures (<1100.degree. F.)
until the aromatic character is destroyed by hydrogenation. That
is, the hydrogenation reactions can lower the bond dissociation
energies for easier cracking. On the other hand, the cracking
reactions can (1) provide olefinic & aromatic intermediates for
hydrogenation and/or (2) create access to heterocyclic compounds,
deeply imbedded in the asphaltenes and resins of the coke mass.
These heterocyclic compounds often contain undesirable impurities
(e.g. S, N, & metals). The major types of cracking reactions in
pet coke hydroprocessing include thermal cracking, catalytic
cracking, and hydrogenolysis. As with hydrogenation, the cracking
reactions are more likely for complex compounds with more aromatic
rings, less symmetry, and some aliphatic character (e.g. bridges).
Consequently, asphaltenes (solutized or otherwise) in the coke mass
have a greater tendency (vs. aromatics and resins) to both
hydrogenate and crack due to their higher molecular weights and
composition.
[0725] As the exothermic hydrogenation reactions proceed,
sufficient heat is generated to initiate additional thermal
cracking. The net heat generated typically creates excess heat that
raises the reactor temperature and accelerates the cracking
reaction rates, until quenched or controlled (via cold hydrogen or
other quench mechanisms). As explained in the prior art of delayed
coking, the hierarchy of ease of thermal cracking is
Paraffins>Linear Olefins>Napthenes>Cyclic
Olefins>Aromatics. Again, resonance stabilization of many
aromatic bonds renders them unbreakable at normal process
temperatures (<1100.degree. F.). Thus, the aromatic compounds
still are not likely to be thermally cracked in the pet coke
hydroprocessing (similar to delayed coking). However, thermal
cracking can crack the cyclic olefins and napthenes, produced by
hydrogenation of aromatic compounds, if temperatures are
sufficient. Temperatures of 800-900+.degree. F. would be required
to thermally crack many of these compounds. As with delayed coking,
process temperatures >800.degree. F. can lead to
dehydrogenation, coking, and vapor overcracking (i.e. light gases
versus cracked liquids). Fortunately, the excess of hydrogen
inhibits these undesirable reactions, even at higher thermal
cracking temperatures. In addition, most of the coke-forming
compounds have already become coke in the more severe delayed
coking process. That is, additional coke formation in the pet coke
hydroprocessing is not likely.
[0726] The addition of certain catalyst materials.can lower the
activation energies of the cracking reactions, reducing process
temperature requirements and/or increasing cracking reactivity of
more troublesome compounds. Heterogeneous catalysts bearing acid
sites can accelerate the rate of cracking at a given temperature
and/or improve the selectivity toward stable products. As with
prior art hydrocracking, pet coke hydroprocessing combines
hydrogenation and catalytic cracking via a bi-functional catalyst.
However, unlike hydrocracking, the semi-solid, coke mass (i.e.
porous coke crystals & pitch-like materials) acts as a cracking
catalyst and has substantially less resistance to hydrogen
diffusion and alignment of reactants (pitch-like materials) to the
catalyst sites (porous coke crystals). Also, the hydrogen radical
formation & transfer (e.g. migration) and reaction mechanism
behaves more like gas-solid phase reactions in adsorption carbon.
Consequently, catalytic cracking reactions can be normally achieved
at lower hydrogen partial pressure (& system pressure) and/or
lower temperatures. This is particularly true for applications
where conversion requirements are lower and residence times are
significantly higher. If greater catalyst activity is needed,
additives can be impregnated on the base catalyst (i.e. porous coke
crystals) via various mechanisms. In many cases, sufficient
catalytic cracking can be achieved at temperatures of 500.degree.
F. to 950.degree. F. (preferably 700.degree. F. to 750.degree. F.)
and pressures of 15 to 2000 psig (preferably 15 to 100 psig). If
more catalyst activity is needed for a given catalyst, increased
temperatures and/or pressures can be effective. In any case, the
catalyst formulation and operating conditions are normally
optimized for each application, depending on coke mass composition
and desired objectives. This approach is similar to hydrocracking
of the prior art.
[0727] Another type of cracking reaction in pet coke
hydroprocessing is hydrogenolysis; cleavage of bonds by hydrogen
addition. In hydrogenolysis, radical hydrogen transfer reactions
can provide an alternative mechanism for cracking strong bonds
(e.g. C.dbd.C; thiophenic C--S), including degradation of aromatic
groups. In the prior art, the transfer of free-radical hydrogen by
an aromatic solvent can achieve this type of cracking. In addition,
the migration of hydrogen radicals from the catalyst surfaces has
also been noted to promote hydrogenolysis. Similar hydrogenolysis
reaction pathways exist in the pet coke hydroprocessing.
Hydrogenolysis reactions can be enhanced in pet coke
hydroprocessing due to (1) less resistance to hydrogen radical
transfer, (2) longer residence times, and/or (3) higher
concentration of aromatic groups in the coke mass. Further
enhancement of hydrogenolysis can be achieved at higher catalyst
activity and/or higher hydrogen partial pressure.
[0728] b3. Conversion of Heteroatomic & Organometallic
Compounds:
[0729] As the asphaltenes and resins hydrogenate and crack,
heteroatomic and organometallic compounds are normally exposed for
further treatment. Hydrogenation of these compounds is more readily
achieved than in the prior art. That is, the hydrogenation and
subsequent cracking of aromatics in the pet coke hydroprocessing
provide access and favorable reaction conditions to hydrogenate
heteroatomic and organometallic compounds that have been
traditionally inaccessible (deep within the organic structures of
asphaltenes and resins). In this manner, sulfur, oxygen, and
nitrogen in the heteroatomic compounds can be transformed to
hydrogen sulfide, water, and ammonia, respectively. These gaseous
compounds can then be removed from the pet coke mass and treated
further. The metals in the organometallic compounds can be
hydrogenated to yield metal sulfides that normally remain with the
coke mass. The degrees of conversion for each type of compound will
depend on various factors, including (1) pet coke mass composition,
(2) degree of aromatic hydrogenation and subsequent cracking, (3)
local hydrogenation catalyst activity and type, and (4) hydrogen
availability at reaction sites (hydrogen partial pressure or
otherwise). Conversion of many heteroatomic and organometallic
compounds often enhances the ability to further hydrogenate and/or
crack the products of these conversion reactions.
[0730] Exposed sulfur compounds are readily converted to hydrogen
sulfide via hydrogenation and hydrogenolysis. Most of the
non-thiophenic sulfur compounds, such as sulfides, thioethers,
thiols, and mercaptans, are normally converted to hydrogen sulfide
by thermal reactions in the coking cycle of the delayed coking
process. The thiophenic sulfur is normally unaffected by thermal
reactions, and typically requires catalytic hydrodesulfurization.
In the pet coke hydroprocessing, thiophenic sulfur compounds and
remaining non-thiophenic sulfur compounds are converted to
primarily hydrogen sulfide and other non-thiophenic sulfur
compounds. Both hydrogenation and hydrogenolysis mechanisms can
effectively convert the thiophenic sulfur.
[0731] Similarly, exposed oxygen compounds are readily converted to
water via hydrogenation. Aromatic hydroxyl and furan compounds are
the predominant oxygen compounds remaining after the thermal
reactions in the coking cycle of the delayed coking process. In the
pet coke hydroprocessing, hydrogenation can readily convert these
compounds to water, which can be subsequently removed from the
process.
[0732] Exposed nitrogen compounds are much less reactive, but can
be converted to ammonia via hydrogenation with the proper catalyst
activity and operating conditions. The nitrogen compounds remaining
in the coke mass are primarily two types: (1) non-basic derivatives
of pyrrole (e.g. pyrroles, indoles, & carbazoles) and (2) basic
derivatives of pyridine (e.g. pyridines, quinolines, &
acridines). Catalysts containing nickel (Ni/Mo or Ni/Co/Mo) tend to
promote hydrodenitrification, but hydrodesulfurization will occur
also. However, unlike catalytic desulfurization, only the
hydrogenation reaction mechanism is prominent in catalytic
hydrodenitrification. The hydrogenation catalyst sites are more
acidic than the hydrogenolysis catalyst sites, and hence tend to be
poisoned by adsorption of the basic nitrogen compounds. Apparently,
the synergistic effects of hydrogen sulfide from
hydrodesulfurization and water from hydrodeoxification can further
promote hydrodenitrification by increasing the catalyst
acidity.
[0733] Hydrogenation of exposed organometallic compounds typically
forms deposits of metal compounds on the catalyst(s). Metals occur
in two basic organic forms: porphyrin metals and non-porphyrin
metals. Porphyrin metals, which are chelated in porphyrin
structures analogous to chlorophyll, have porphyrin rings, based on
pyrrole groups which complex the metal atom. The non-porphyrin
metals (e.g. metal naphthenates) are thought to be associated with
the polar groups in asphaltenes. Metal removal typically occurs
during both thermal and catalytic processing. However, removal is
more complete when a catalyst provides much more effective hydrogen
transfer. In pet coke hydroprocessing, the organometallic
compounds, such as porphyrins and metal naphthenates, can decompose
and transform to metal sulfides (e.g. nickel, iron, and vanadium
sulfides) in a colloidal state with particle sizes ranging form 20
to 250 nm. These metal sulfides can enhance hydrogenation catalyst
activity and increase hydrogen availability and reactivity.
However, these metal sulfides (e.g. rod-like crystals of vanadium
sulfide: V.sub.3S.sub.4) can accumulate and cover the catalyst
surface and/or block macropores in the catalyst/support structure.
Fortunately, the pet coke mass in the pet coke hydroprocessing
normally has sufficient macropore structure in the porous, pet coke
to accommodate high conversions of metals to metal sulfides. That
is, the weight ratio of porous, pet coke to metals content of the
coke mass is typically >100:1. As such, the accumulation of
metal sulfides on the pet coke mass does not normally inhibit its
catalytic activity, but enhances it.
[0734] c. Residence Time:
[0735] The residence time of pet coke hydroprocessing reactions can
vary considerably, depending upon the selection of reaction
vessel(s) for each application. As discussed previously, the
reaction vessel considerations provide three potential scenarios
for the pet coke hydroprocessing: (1) coke drums (existing or new)
in the traditional delayed coking configuration (i.e. 2 coke drums
& 2 coking cycles), (2) existing/new coke drums in a modified
configuration (i.e. 3 coke drums & 3 coking cycles), or (3) new
reaction vessel(s) in a separate pet coke hydroprocessing unit.
[0736] If coke drums are used in the traditional delayed coking
configuration. the residence time of pet coke hydroprocessing
reactions can be limited: <15 minutes to >2 hours. The
optimal residence time will depend on design and operating
constraints of the existing delayed coking cycles, as well as the
required time to achieve site-specific, pet coke hydroprocessing
objectives. Equipment constraints, such as coke drum pressure
limitations and coker subsystem bottlenecks can also influence
sufficient residence time.
[0737] Residence time limits in the pet coke hydroprocessing can be
dramatically loosened by the use of 3 coke drums (existing and/or
new) in 3 coking cycles. In this reaction vessel scenario, the
residence time can be as long as the existing coking cycle (e.g.
12-16 hours). However, lower residence time for pet coke
hydroprocessing is more likely to allow (1) movement of traditional
decoking cycle tasks to the pet coke hydroprocessing cycle and/or
(2) additional distillate/gas oil hydrotreating capacity in the pet
coke hydroprocessing cycle. In this case, the time for each cycle
time can be reduced and increase coke feed throughput capacity.
[0738] The pet coke hydroprocessing residence time has few design
limits, if new reaction vessel(s) is/are built for a separate pet
coke hydroprocessing unit. However, the residence time impact on
costs can be prohibitive in achieving an acceptable return on
investment(s).
[0739] d. Catalysts:
[0740] Unlike the hydroprocessing of the prior art, the petroleum
coke is not only the process feed, but can also play a major role
in the catalysis of the desired reactions. That is, the pet coke
(1) behaves as a hydrogenation catalyst, (2) acts as a cracking
catalyst, (3) provides surface area for catalyst impregnation,
and/or (4) produces metal sulfide hydrogenation catalysts. The
porous pet coke in the coke mass can also provide a bi-modal
distribution of catalyst pores to enhance its catalytic cracking
activity. In addition, the pet coke hydroprocessing conditions
limit catalyst deactivation. In this manner, the porous pet coke in
the coke mass provides bifunctional catalyst properties and
deactivation resistance required for pet coke hydroprocessing.
[0741] The pet coke can perform the function of a hydrogenation
catalyst. As discussed previously, sponge, pet coke with sufficient
carbon adsorption character can adsorb oxygen molecules and break
them down into reactive ion radicals. Similarly, this sponge coke
can also adsorb hydrogen molecules and break them down into
reactive ion radicals. This is particularly true for the highly
porous sponge structure of the modified pet coke in the current
invention. That is, the lower asphaltene/resin to aromatics ratio
normally provides less liquid and more solidified, porous sponge
coke in the coke mass.
[0742] The solidified, porous crystalline structure of the
semi-solid coke mass can act as a cracking catalyst, too. In many
ways, the large internal surface area of highly porous, sponge coke
behaves like silica-alumina in its adsorption capabilities. The
adsorption and breakdown of hydrogen molecules provides the rapid
transfer of reactive hydrogen radicals to (1) catalyze thermal
cracking reactions at lower activation energies and temperatures
and (2) directly break strong bonds via hydrogenolysis. As pet coke
hydroprocessing proceeds, the sponge coke portion of the coke mass
increases, as well as its porosity, adsorption character, and
catalytic activity. Thus, the catalytic cracking activity can
normally accelerate.
[0743] The solidified, sponge coke portion of the coke mass
provides porous surface area for: the impregnation of various
catalyst enhancing compounds. If the pet coke does not provide
sufficient catalytic activity to initiate sufficient hydrogenation
and/or cracking, the porous sponge coke can be impregnated (or
seeded) with finely divided, catalytic additives (e.g. Ni, Co, Mo,
Fe). However, the recovery of these catalytic additives would be
difficult and expensive. Therefore, less expensive catalytic
additives, such as iron sulfate or iron oxide wastes, would be
preferable. Furthermore, fine particles of silica-alumina can also
be added to the coke mass to increase catalytic cracking activity,
if needed. In addition, other additives can be used to enhance
catalyst activity, such as increased acidity of the reaction sites.
For example, acidity can be increased by substitution reactions
increasing the concentration of alkaline earth metals, rare earth
metals, or hydrogen.
[0744] The hydrogenation of heteroatomic and organometallic
compounds can produce additional hydrogenation catalysts. As
discussed previously, metal sulfides (i.e. sulfides of Ni, Fe,
& V) can form from the chemical combination of sulfur and
metals from hydrogenation of organic sulfur and metal compounds in
the coke mass. These metal sulfides can be good hydrogenation
catalysts to a limited extent. In excess, these metal sulfides can
block catalyst pores and poison certain catalysts. However, the
metal sulfides are limited by the concentration of the metals in
the coke mass in this (semi-continuous or batch) process. Since the
metals content of the coke mass is typically <0.2% by weight,
the accumulation of metal sulfides is not normally sufficient to
cause significant detrimental impacts. Thus, the net effect
typically favors increased hydrogenation activity.
[0745] The pet coke hydroprocessing operating conditions limit
catalyst deactivation by coke fouling and/or poisoning by nitrogen,
oxygen, or metals. Catalysts in pet coke hydroprocessing are not as
susceptible to coke fouling. Compounds having coke forming
tendencies have already become coke in the coke mass. Therefore.
not likely to foul catalyst with additional coke formation in the
presence of hydrogen.
[0746] Bi-functional catalyst can be formulated to meet the
site-specific objectives and constraints for each application of
pet coke hydroprocessing.
[0747] e. Overall Process: Interaction of Various Reactions:
[0748] In the pet coke hydroprocessing, a formidable combination of
various reactions and chemical species usually occur
simultaneously. These reactions potentially include (1) various
types of hydrogenation reactions with aromatic compounds, olefins,
and heterocyclic compounds (i.e. containing sulfur, oxygen,
nitrogen, and/or various metals), (2) various types of cracking
reactions: thermal, catalytic, and hydrogenolysis, and (3) various
types of coke-forming reactions: dehydrogenation, condensation,
aromatization, oligomerization, polymerization, and cross-linking.
The complexity of reaction mechanisms is further complicated due to
simultaneous thermal and catalytic reactions (cracking &
otherwise). Consequently, selecting catalysts and operating
conditions that enhance desirable reactions and/or inhibit
undesirable reactions is critical to achieve objectives in each
application of pet coke hydroprocessing. As discussed previously,
other site-specific factors and constraints can have significant
impacts on the optimization of pet coke hydroprocessing. These
site-specific factors (and associated examples) include, but should
not be limited to:
[0749] 1. Coke Mass Composition and Physical Properties: SARA;
hetero-contents; % solid, porosity
[0750] 2. Reaction Vessel Constraints: Number; new/old; pressure
limitations;
[0751] residence time
[0752] 3. Coke Product Specifications: Fuel requirements;
adsorption carbon characteristics; other
[0753] 4. Economic Constraints: Capital and operating costs,
product values; acceptable conversion
[0754] The basic interaction of process temperature, hydrogen
availability, and catalyst activity are shown in the simplified
diagram of FIG. 9. The points of the triangle represent the highest
value for each variable, and the opposite side represents minor to
negligible value for that same variable. In the delayed coking
process, the process temperature (e.g. 850-925.degree. F.) is near
its highest practical value (i.e. lower left point of triangle),
while catalyst activity and available hydrogen (e.g. partial
pressure) are minor to negligible. Thus, the primary reactions of
residual components are dehydrogenation and coking; forming the
coke mass of concern in the pet coke hydroprocessing. As seen in
this diagram, hydrogenation can be preferentially achieved by
increasing the hydrogen availability (e.g. hydrogen partial
pressure or otherwise) and catalyst activity, while decreasing
temperature. If pressure limitations of the reaction vessel limit
the hydrogen availability, then higher catalyst activity with lower
process temperatures can maintain operation in the hydrogenation
regime: Zone 1 Operating Conditions. If the coke drums are modified
to remove pressure limits (e.g. new drums w/advanced metallurgy and
proper thickness), the hydrogenation operating regime can be
maintained with higher hydrogen availability and lower
temperatures, in lieu of higher catalyst activity. These operating
conditions are represented by Zone 3 in FIG. 9. The coke drums in
many existing coker applications can have limited hydrogen
availability (e.g. drum pressure limits) and catalytic activity
(e.g. less ability to impregnate coke w/catalyst). In these cases,
Zone 2 operating conditions may be preferred due to higher reliance
on temperature versus hydrogen availability or catalyst activity.
As noted previously, different feeds can result in different
operating regimes (e.g. hydrogenation vs. dehydrogenation), even at
identical operating conditions (i.e. temperature, hydrogen
availability, & catalyst activity). Thus, this diagram has
limited use for absolute values of the respective operating
conditions, but provide their relative impacts on the hydrogenation
operating regime. Consequently, pilot scale tests are often needed
to refine operating conditions of this technology for a given feed.
The preferable operating conditions would be in the hydrogenation
operating regime, at a point where the overall process
profitability is maximized, based on site-specific operating
constraints.
[0755] The interactions between catalytic and thermal reactions
with the various residual compounds can be very complex. Some of
the reactions are reversible. Their reaction mechanisms and
equilibrium can often be determined by the (1) specific compounds
& impurities in feed, (2) quality & quantity of
catalyst(s), and (3) various process conditions, including process
temperature & hydrogen partial pressure. For example,
polyaromatics, in the presence of hydrogen and catalyst(s), can
undergo cycles of hydrogenation and dehydrogenation. Furthermore,
cracking reactions would proceed via various free-radical reaction
mechanisms, including abstraction of aliphatic, napthenic, and
aromatic hydrogen atoms, along with hydrogenolysis. Catalyst
activity for both hydrogenation and hydrogenolysis may depend
greatly on the transfer of hydrogen radicals. Thus, interaction of
hydrogenation and hydrogenolysis may be a key parameter that may be
addressed on a case-by-case basis. A suggested way to look at
optimization of the current technology to specific applications is
FIG. 9.
[0756] Optimal pet coke hydroprocessing of the current invention
would often inhibit coke-forming reactions and promote certain
hydrogenation and cracking reactions. The hierarchy of desirable
reactions for many applications of pet coke hydroprocessing likely
includes:
[0757] 1. Hydrogenation & cracking of asphaltenes & resins:
Reduce coke yields; Better coke quality
[0758] 2. Iterative hydrogenation/catalytic cracking of
intermediates: Improve liquids yield; Inhibit gas
[0759] 3. Hydrogenation/hydrogenolysis of sulfur compounds:
Substantially improve coke quality
[0760] 4. Hydrogenation of nitrogen compounds: Improve coke fuel
quality; reduce catalyst poison
[0761] 5. Hydrogenation of organometallic compounds: Enhance
catalyst activity; limited coke effect
[0762] 6. Hydrogenation of oxygen compounds: Reduces coke fuel
quality; impacts adsorption quality
[0763] In many of these cases, the desirability of the last three
types of reactions is questionable. Fortunately, these three types
of reactions are more difficult to achieve on a thermodynamic
basis. Thus, the remaining discussion will focus on the first three
types of reactions.
[0764] These complementary hydrogenation and cracking reactions
proceed until the desired conversion of the coke mass is achieved:
production of cracked components with lower boiling points and/or
the removal of undesirable impurities, including sulfur and
nitrogen. The gases generated (hydrocarbons w/ B.P. <850.degree.
F., hydrogen sulfide, ammonia, and water) are released or withdrawn
form the reaction vessel with excess hydrogen. Similar to
hydroprocessing of the prior art, the gases are separated by high
and low pressure flash separators: the hydrocarbons are sent to a
fractionator system, while the overhead gases are passed through an
amine stripper. The hydrogen rich gas is recycled and the rich
amine solution goes to the sulfur plant for further processing.
When the reactions are sufficiently complete, the reactor can be
depressurized and quenched. After cooling to roughly 200.degree.
F., the coke can be safely removed from the reactor vessel.
[0765] Simultaneous hydrogenation and cracking of the coke mass are
initiated and proceed with sufficient residence time to obtain the
desired conversion. As the hydrogen enters the system, the very
porous, solidified coke within the coke mass (and its increased
adsorption character in this exemplary embodiment) convert the
molecular hydrogen to free radical ions without catalyst additives.
As discussed previously, the adsorption character of the coke mass
and the solid-gas phase nature of coke hydroprocessing make the
hydrogen free radicals readily available for migration to the
reaction sites without excessive hydrogen partial pressure. The
reaction sites are normally the surface of the reactants (e.g.
asphaltenes, resins, & condensed aromatics). The high
concentrations of both reactive molecules and hydrogen free
radicals create driving forces for high degrees of complementary
hydrogenation and cracking reactions. Normally, the hydrogenation
and cracking reactions preferentially attack the weaker bonds of
the asphaltenes and resins. Significant breakdown and removal of
complex aromatic compounds (preferably asphaltenes and resins) from
the coke mass create additional voids in the coke crystalline
structure. The size of these voids range form <2 nanometers to
>50 nanometers. As a result, additional micropores, mesopores
and macropores. This is analogous to the removal of basal planes in
the steam activation of carbonized carbons to produce high-quality
activated carbons. Ample residence time of the exemplary embodiment
allows lower operational temperatures that favor greater aromatic
saturation.
[0766] In most cases, the resulting petroleum coke has
significantly less mass, lower density, higher porosity, and
greater carbon adsorption character. The cracking and hydrogenation
of heavy compounds (preferably asphaltenes and resins) in the coke
mass normally leaves additional voids in the coke mass. In turn,
any further polymerization and cross-linking of the remaining coke
mass often becomes more optimal due to a lower asphaltene/resins to
aromatics ratio. After cooling, the pet coke typically has greater
internal surface area, with significantly more micropores and
mesopores. The increased carbon adsorption character can improve
fuel properties via better adsorption of VCMs, sulfur reagents,
etc. With sufficient cracking and hydrogenation of the coke mass,
the resulting pet coke can also provide sufficient carbon
adsorption character for treatment applications similar to
traditional activated carbon.
[0767] Alternatively, additional hydrotreating of distillates can
be achieved before quench and coke cooling, if sufficient time is
allotted for semi-continuous process cycles (i.e. batch process).
That is, distillates can be added with excess hydrogen while the
temperature and pressure of the coke are still sufficient for
hydroconversion (e.g. hydrotreating). The distillates can be
recycled through the coke bed with excess hydrogen until sufficient
hydroconversion has occurred. The types of distillates include, but
should not be limited to various gas oils, middle distillates, and
naphthas. Preferably, the distillates, such as coker gas oils, can
come directly from the coke fractionation unit, eliminating the
need for substantial heating to reaction temperatures. Depending on
solvent action of the distillate, additional separation may be
necessary in some cases to remove excess asphaltenes, resins, and
heavy aromatics solutized from pet coke mass.
[0768] The above theory of operation generally applies to the
hydroprocessing of pet coke. However, this theory of operation may
not accurately describe all applications. Therefore, this theory of
operation should not limit the current invention, and should be
used as a guide for ones skilled in the art to modify this
technology for specific applications.
[0769] In this manner, the hydroprocessing of pet coke can be
generally achieved with the proper catalysts. As with other
hydroprocessing technologies the catalysts are tailor-made for the
feedstock (e.g. coke mass characteristics), process operating
conditions, and conversion levels desired. One skilled in the art
can make the necessary adjustments in catalyst (type, character,
and quantity) and operating conditions, based on engineering
calculations, and minor tests, if necessary.
[0770] (3) Exemplary Embodiment: Coke Hydroprocessing:
[0771] In an exemplary embodiment, process options of the current
invention are used to substantially decrease overall coke yield and
produce a petroleum coke with adsorption characteristics
approaching traditional activated carbons of high quality. A third
coke drum is added to the traditional coke drum pairs of
traditional prior art (i.e. groups of 3 vs. 2). A third coking
cycle is also added. The three cycles become coking, coke
hydroprocessing, and decoking. In the coking cycle, the adsorption
character of the petroleum coke is substantially increased via
process options of the current invention. In the coke
hydroprocessing cycle, initial coke cooling is followed by
simultaneous hydrogenation and cracking of the coke mass, which
proceeds with sufficient residence time to obtain the desired
conversion. The remaining hydroprocessing cycle time is used for
further cooling of the petroleum coke with traditional coke quench
media. In the decoking cycle, the coke quench is completed and
traditional decoking cycle tasks (coke cutting, reheat, etc.) are
accomplished.
[0772] Equipment modifications of delayed coking processes include,
but should not be limited to:
[0773] 1. Addition of a third coke drum; Preferably 3 new coke
drums w/higher pressure limits
[0774] 2. Hydrogen; addition/recycling system
[0775] 3. Catalyst additives; storage & injection system
[0776] 4. Associated piping, instrumentation, & controls
[0777] The primary process modifications involve the addition of
the third process cycle and the modifications & redistribution
of process tasks. The primary purpose of the third process cycle is
to provide sufficient residence time for the coke hydroprocessing
step. By incorporating tasks of the traditional decoking cycle,
this coke hydroprocessing cycle also allows potential increase in
coker capacity via reduction in coking cycle time. That is, the
heater section becomes the limiting factor in reducing cycle times.
Though the overall coker cycle time increases, the cycle time to
fill each coke drum can be reduced, increasing coker capacity. For
example, a coker with current cycle time of 14 hours has an overall
coker cycle of 28 hours. In contrast, the third coker process cycle
can effectively reduce the individual cycle times to 12 hours, but
extend the overall coker cycle to 36 hours. However, one coke drum
(of the same size or larger) is filled every 12 hours, instead of
14 hours, increasing the coke capacity.
[0778] In the coking cycle, the adsorption character of the
petroleum coke is typically increased to improve coke mass
reactivity. This objective can be usually achieved by the use of
previously discussed process options of the current invention.
These process options include lower heater outlet temperature,
lower recycle rate, higher drum pressure, and/or modified coker
feed with higher aromatics content. In this manner, the ratio of
asphaltenes/resins to aromatics is low enough to consistently
produce highly porous sponge coke or honeycomb crystalline
structure. These high porosity, coke crystalline structures provide
sufficient solidification of coke mass and adsorption character to
improve coke mass reactivity. In addition, the lower heater outlet
temperature, lower recycle rates, and lower coke density (i.e. less
coke per coking cycle) reduce the heater section limitations and
increase coke drum fill rates. This allows potential reduction in
coking cycle time (e.g. 12 hours) and increases in coker
capacity.
[0779] In the coke hydroprocessing cycle, initial pet coke cooling,
hydrogen/catalyst addition, pet coke hydroprocessing, and further
pet coke cooling occur. The initial pet coke cooling provides (1)
optimal reaction temperature, (2) increased coke mass
solidification, and (3) the means to inject hydrogenation catalyst
additives, if necessary. As noted previously, the optimal
temperature and pressure depend on site-specific factors, including
the coke mass composition & structure and hydroprocessing
objectives. In many cases, the optimal temperature for coke
hydroprocessing is normally 500 to 950.degree. F. (preferably 700
to 800.degree. F.) and pressures of 15 to 2000 psig (preferably 15
to 100 psig). Secondly, the lower temperature (vs. 800 to
850.degree. F.) also increases the solidified coke content of the
semi-solid coke mass. As discussed previously (i.e. theory of
operation), the highly porous, solidified coke in the semi-solid,
coke mass provides the carbon adsorption character that increases
the availability of the hydrogen free radical ions in predominantly
solid-gas phase reactions. Finally, the initial coke cooling can
provide the means to add hydrogenation catalyst additives, such as
iron oxides and/or iron sulfates. Traditional coke cooling media
(e.g. steam, water, & sludges) can be used to attain the
optimal temperature. Various catalyst additives can be injected
with these media, particularly aqueous sludges, but other options
may be preferable to achieve better control and more uniform
distribution in the coke. One alternative would include the use of
a coker fractionator slipstream to serve as both carrier fluid and
cooling medium. This slipstream (e.g. light coker gas oil or heavy
naphtha) would preferably vaporize at temperatures below the
optimal hydroprocessing reaction temperature. The catalyst
additive(s) (e.g. iron oxide waste sludges) would be mixed with
carrier oil/distillate prior to injection. The vaporization of the
carrier oil/distillate would provide the desired cooling (with
better control than water expanding to steam) and leave the
catalyst additives uniformly deposited on the pet coke surfaces.
This would be similar to the deposition of SOx sorbents discussed
later. The vaporized carrier oil/distillate would be recovered. One
skilled in the art could readily design and implement such a system
addressing site-specific needs and concerns. This initial coke
cooling typically requires 2 to 3 hours of coke hydroprocessing
cycle time.
[0780] Initial hydrogen addition can be injected with the cooling
media, the bulk of the hydrogen is added after the optimal
temperature is reached. As the hydrogen is added to the coke drum,
the system pressure is allowed to increase to the practical
pressure limits of the coke drums. For existing coke drums, this
pressure limit is typically 80-100 psig. A circulation rate of
excess hydrogen is established with 1.5 to 8 times (preferably 3-4
times) the hydrogen required for conversion. This excess hydrogen
circulation provides the means to remove gaseous reaction products
(e.g. hydrogen sulfide, ammonia, water, etc.) for further
processing and recovery of vaporized hydrocarbons. The hydrogen is
recovered and recycled. Based on experience in other
hydroconversion processes, one skilled in the art can design and
implement a hydrogen circulation and product recovery system, which
addresses site-specific factors and concerns. Establishing hydrogen
circulation and higher drum pressure can normally be achieved
within 2 hours (preferably <1 hour) of cycle time.
[0781] Simultaneous hydrogenation and cracking of the coke mass are
initiated and proceed with sufficient residence time to obtain the
desired conversion. As the hydrogen enters the system, the very
porous, solidified coke within the coke mass (and its increased
adsorption character in this exemplary embodiment) convert the
molecular hydrogen to free radical ions without catalyst additives.
As discussed previously, the adsorption character of the coke mass
and the solid-gas phase nature of coke hydroprocessing make the
hydrogen free radicals readily available for migration to the
reaction sites without excessive hydrogen partial pressure. The
reaction sites are normally the surface of the reactants (e.g.
asphaltenes, resins, & condensed aromatics). The high
concentrations of both reactive molecules and hydrogen free
radicals create driving forces for high degrees of complementary
hydrogenation and cracking reactions. Normally, the hydrogenation
and cracking reactions preferentially attack the weaker bonds of
the asphaltenes and resins. Significant breakdown and removal of
complex aromatic compounds (preferably asphaltenes and resins) from
the coke mass create additional voids in the coke crystalline
structure. The size of these voids range form <2 nanometers to
>50 nanometers. As a result, additional micropores, mesopores
and macropores are created. This is analogous to the removal of
basal planes in the steam activation of carbonized carbons to
produce high-quality activated carbons. Ample residence time of the
exemplary embodiment allows lower operational temperatures that
favor greater aromatic saturation. The third coke drum and third
coker operational cycle of the exemplary embodiment provide ample
residence time of at least 3-12; preferably 4-6 hours.
[0782] The remaining hydroprocessing cycle time is used for further
cooling of the petroleum coke with traditional coke quench media.
When the coke hydroprocessing has achieved the desired conversion
level, the pet coke is steamed out and cooled further for cutting
from the coke drum. Similar to delayed coking of the prior art, the
petroleum coke is cooled to a temperature sufficiently low (e.g.
200.degree. F.) to safely remove the pet coke form the coke drum.
However, the remaining coke hydroprocessing cycle time (e.g. 2-3
hours) can be effectively used to reduce the rate of cooling and
reduce thermal stress in the coke drums. As a result, all tasks of
the coke hydroprocessing can be readily completed within a 12-hour
cycle time.
[0783] In the decoking cycle, traditional decoking cycle tasks can
be readily accomplished within a 16-hour (preferably 12-hour) cycle
time with less thermal stress on the coke drums and less safety
concerns. First, substantial cooling (e.g. 3-6 hours at reduced
cooling rates) has already occurred in the coke hydroprocessing
cycle. Consequently, coke cooling can often be completed within the
first 2-3 hours. The next 6-8 hours are available for draining,
unheading, decoking, head-up, and testing. The remaining cycle time
(e.g. 2-3 hours) can be effectively used for warming up the drum at
a lower rate, reducing thermal stresses in the coke drums. One
skilled in the art of delayed coking can determine the optimal use
of cycle time for the different tasks. The proper allocation of
decoking cycle time can depend on site-specific factors, including
various safety concerns, coke drum conditions, coke cutting design
& controls, and coke transfer facilities.
[0784] The primary results of the exemplary embodiment include (1)
substantial reduction in overall coke yields, (2) significant
improvement in pet coke adsorption quality, (3) removal of coke
impurities, and (4) higher coker capacity via reduction in cycle
time of individual cycles, particularly coking cycle. The purpose
and benefits of the exemplary embodiment can be illustrated by the
following example. A delayed coker currently has a coke yield of
33% and coking cycle time of 16 hours. A fuel-grade, petroleum coke
is produced with shot coke crystalline structure, 10% VCM, and an
in-drum density of 0.98 g/cc. With an exemplary embodiment coking
cycle of 12 hours, the modified operating conditions produce a
highly porous coke with honeycomb crystalline structure to promote
the coke hydroprocessing. This coke has an in-drum density of 0.86
g/cc and roughly 22% VCM. The coke yield is increased to
approximately 37%. With a 25% hydroprocessing conversion, the
overall coke yield is reduced to 28% and the modified petroleum
coke is similar in quality to medium grades of traditional
activated carbons. By increasing the hydroprocessing conversion to
35%, the overall coke yield is reduced to 24% and the modified pet
coke approaches the quality of premium activated carbons.
Obviously, the lafter scenario is more desirable with an effective
reduction in overall coke yield of 9 wt. % (i.e. 33%-24%),
primarily conversion to cracked liquids during the coke
hydroprocessing. In addition, the cycle times have been reduced to
the lowest practical levels: 12 hours. Though the increase in coker
capacity would appear to be 33% (i.e. 16/14), the change in coke
densities reduces the weight of coke in each coking cycle by 14%.
Thus, the net increase in coker capacity would be roughly 19%. Even
if the coking cycle time can only be reduced by 2 hours, the higher
drum fill rate can cover the change in coke densities and still
increase coker capacity by 0.3%.
[0785] One skilled in the art can make proper equipment and
operational modifications to achieve the desired objective at
site-specific application of this technology. As discussed
previously, the application of the current invention can vary due
to site specific factors, including existing coker design and
operation, coker feeds, coke mass composition, hydroprocessing
objectives, and use(s) of the modified petroleum coke.
[0786] (4) Other Embodiments: Coke Hydroprocessing
[0787] 1. This method can be performed without coke crystalline
modification of the current invention. some cokers won't need (e.g.
sweet crude refineries)
[0788] 2. Lower coke hydroprocessing reaction temperature (e.g.
500-700.degree. F; preferably 600-700.degree. F.): Hydrogenation
reaction equilibrium favors low temp; residence time/reaction rate
trade-offs
[0789] 3. Reduce conversion; Maximize profitability: Adsorption
coke higher value vs. cracked liquids
[0790] 4. Reduce conversion for fuel grade pet coke applications:
Boiler & MHD Technology
[0791] 5. Use remaining cycle time for additional hydrotreating
capacity: Gas oils, naphthas, etc.
[0792] 6. Add other additives to improve catalyst activity;
[0793] 7. New coke drums/reaction vessels designed for higher
process and hydrogen partial pressures
[0794] New alloy clad drums w/latest technology; repetitive seals
& press effects/thermal cycles
[0795] 8. Add other process options of current invention:
Plastics/Rubber, Mod Drill Stem, etc.
[0796] Coke Fuel Product: SOx sorbents, VCMs, oxygen, ionization
chemicals
[0797] Coke Adsorption product: Chemisorption, other adsorption
enhancing additives
[0798] Add oxygen, nitrogen, and/or halogen surface groups or
complexes to enhance adsorption character & chemisorption
properties for specific adsorption applications
[0799] During this coke quench, chemisorption or other additives
(e.g. sulfur) can be uniformly impregnated on the pet coke's
adsorption carbon surface via process options of the current
invention.
[0800] Modified coke drum skirt to allow cutting of large honeycomb
chunks: low Press D
[0801] 9. Part of coke to MHD Cogeneration (e.g. on-site) &
Remainder to adsorption uses
[0802] 10. 2-Stage thermal process: 700-750.degree. F. for aromatic
saturation; then raise temperature for thermal/catalytic cracking
to 800-900.degree. F: Alternate for prescribed periods of time in
pet coke hydroprocessing cycle of modified delayed coking
process.
[0803] 11. Carrier fluids (liquid and/or gas) can also be
preferable to improve reactivity and overall benefits; Use of
various hydrocarbons for incremental hydrotreating/hydrocracking
capacity in refinery w/low severity requirements; gas oils or FCCU
slurry oil as carrier for H2 & Fe for hydrocracking in pet
coke
[0804] 12. Reduce overall process coke yield via cracking &
hydrogenation of coke compounds
[0805] 13. Reduce sulfur, nitrogen, and metals contents of the
modified petroleum coke: H2: hydrotreat liquid/coke mass to remove
any exposed S, N, and the metals before coke crystal growth
[0806] 14. Reduce coke yield & improve coke qualities via
optimized coke condensation: addition of hydrogen: promote
stabilization of coke crystals
[0807] 15. Improve carbon adsorption character; approaching
activated carbon applications: H2: lowest molecular weight gas
promotes micro-pores and mesopores; H2: stabilize coke crystals by
saturating and help cross-linking; eliminate pitch like material,
& promote crystal growth
[0808] 16. Densities of Desired Activated carbon quality used as
basis for degree of conversion or maximum conversion of pet coke
and accept whatever quality of pet coke at end
[0809] 17. Incremental hydroprocessing capacity and/or additional
gas oil production from lower heater outlet temperature: excess gas
oil can be pumped to the 3rd coke drum for hydrocracking coke in
presence of hydrogen, iron, and gas oil
[0810] 18. Variations among refineries due to trade-offs: technical
& economical; One skilled in the prior art can.
[0811] (5) Overall Results
[0812] 1. Operate coking cycle at lower temperatures to assure
sufficiently porous, sponge coke
[0813] 2. Reduce coking cycle time to limits of heater section:
e.g. 12 hours
[0814] 3. Cool coke to 600-750.degree. F. with coker gas oil
sidestream and add catalyst additive, if needed
[0815] 4. If cycle time is sufficient (e.g., about 3-4 Hr.),
additional hydrotreating capacity (e.g. coker gas oils)
[0816] 5. Incorporate initial cooling in hydroprocessing cycle time
(e.g., 3-4 Hr.)
[0817] 6. Finish cooling in decoking cycle, integrating desired
coke additives and properties
[0818] 7. Reduce all cycle times to lowest practical levels:
Increase coker capacity & liquid yields
[0819] 8. Design pet coke magnetohydrodynamic cogeneration;
Refinery power and steam production
[0820] 9. Substantially increase refinery efficiency (e.g.
>90%); Reduce CO2 & global warming
[0821] 10. Excess refinery gas to natural gas & plastics
production;
[0822] 11. Excess coke to carbon adsorption applications (not
flooding market; moderate price)
[0823] E. Pet Coke Activation: Chemical Extraction
[0824] A method for activation of petroleum coke for use in carbon
adsorption applications was discussed in coke hydroprocessing
process of the current invention. Certain types of chemical
extraction were discovered as an alternative method for pet coke
activation. The methods of chemical extraction are briefly
described below.
[0825] The chemical extraction methods that activate the pet coke
target the removal of the asphaltenes and resins form the coke mass
in the delayed coking process. Tetrahydrofuran (THF) or similar
solvents can be used in the decoking cycle to extract the
undesirable asphaltenes and resins. Asphaltenes and resins are
normally soluble in THF, but most coke solids are not. Thus,
washing or soaking the pet coke in liquid THF for a sufficient
period of time can be effective in removing the asphaltenes and
resins. The removal of the asphaltenes and resins creates voids of
various sizes in the pet coke: macropores, mesopores, &
micropores. The quality or grade of the adsorption carbon will be
determined by the distribution of the pores in the resultant pet
coke. This pore distribution can depend on various factors,
including but not limited to (1) initial coke crystalline
structure, (2) localized concentrations of asphaltenes/resins, (3)
extent of physical & chemical attachment to coke structure, and
(4) the degree of extraction.
[0826] An exemplary embodiment for this chemical extraction method
would extract the asphaltenes and resins in the decoking cycle of
the delayed coking process. In the decoking cycle, the coke mass is
cooled to a temperature sufficiently low and/or pressure is
increased sufficiently to maintain THF as a liquid. For example,
the coke is traditionally cooled to 200.degree. F. prior to
draining, deheading, and cutting. The drum pressure may have to be
maintained >30 psig to assure liquid THF (i.e. B.P=152.degree.
F. at 14.7 psig) during extraction. Once quench media is drained
and the desired operating conditions are established, liquid THF is
injected into the coke mass until the coke drum is full. After
sufficient residence time to allow appropriate solvent activity the
THF extract is drained. This step can be repeated, if necessary to
achieve the desired degree of extraction. After the extraction is
complete, the solvent extract is drained into a THF recovery
system. After the THF extract is drained, the drum pressure is
reduced and the remaining THF is vaporized. If needed, low-pressure
steam is swept through the coke to remove any residual THF held by
adsorption forces. Both the vaporized THF and steam are piped to
the THF recovery system. In the THF recovery system, the liquid THF
in the extract is vaporized in a flash separator at sufficiently
low pressures. The design of the THF separator would provide means
to readily remove the precipitated asphaltenes and resins. The
vaporized THF is treated, if necessary, and recycled for the next
drum of coke. Make-up THF is added, as needed.
[0827] Other embodiments of this chemical extraction method would
include the following:
[0828] 1. Other solvents that have preferable solvent properties,
physical properties and/or costs; For example: 2-methyl-THF has a
higher normal boiling point of 250.degree. F.
[0829] 2. This method of chemical extraction can be performed in
vessels external to coking process.
[0830] 3. This method of chemical extraction can be performed in a
3 drum coker with 3d cycle.
[0831] 4. This method can be used in conjunction with coke
hydroprocessing of the current invention.
[0832] 5. This method can be performed without coke crystalline
modification of the current invention.
[0833] 6. Reduced pressure vaporization of the solvent can be used.
to further cool the pet coke.
[0834] F. Chemical Activation of Pet Coke for Carbon Adsorption
[0835] Methods for activation of petroleum coke for use in carbon
adsorption applications were discussed in coke hydroprocessing and
chemical extraction sections of the current invention. It has been
further discovered that the pet coke can be chemically activated
for use in carbon adsorption applications. The methods of chemical
activation are briefly described below.
[0836] The prior art of traditional chemical activation for
activated carbons uses various chemicals to develop pores in
carbonaceous materials. Chemical activation normally involves the
following mechanisms: (1) chemical decomposition of certain parts
of the carbonaceous material (e.g. cellulosic content of peat or
wood), and/or (2) chemical support that does not allow resulting
char to shrink during carbonization. The result is a very porous
carbon structure that is filled with activation agent. The
activation agent is typically washed from the carbon and recycled.
The two most common activation agents in commercial use are
dehydrating agents: zinc chloride and phosphoric acid. Many other
chemicals have been noted to activate carbonaceous materials, but
only two others have been used commercially: sulfuric acid and
potassium sulfide. A standard Oil process using anhydrous potassium
hydroxide is operated on a semi-commercial scale.
[0837] In the past, petroleum coke has had limited success as a
carbonaceous raw material for the production of activated
adsorption carbon. However, the modified crystalline structure of
the current invention provides a much better starting material than
traditional petroleum coke. Chemical activation of the modified
coke of the current invention can be performed within the coking
unit or separately. Preferably, the chemical activation occurs in
the decoking cycle of the delayed coking process. Essentially, the
optimal activation chemical is added to the porous sponge (or
honeycomb) coke until the existing voids are filled. Soaking the
modified coke for sufficient residence time at sufficient
temperature decomposes certain coke materials (preferably
asphaltenes and resins), leaving additional voids or pores in the
coke. The quantity and types of pores (i.e. macropores, mesopores,
and/or micropores) can be controlled to a certain extent, producing
low to medium quality adsorption carbons at lower costs. In some
cases, additional porosity and adsorption quality can be achieved
by leaving the activation agent in the pet coke, followed by
further carbonization in the proper furnace (e.g. rotary kiln).
However, the additional costs are often not justified.
[0838] An exemplary embodiment for chemical activation in the
current invention uses molten anhydrous potassium hydroxide in the
delayed coking unit. Preferably, the modified pet coke of the
current invention is created in the coking cycle via optimization
of the cracking and coking reactions. Using this very porous pet
coke as the starting raw material helps (1) improve the
effectiveness of the molten anhydrous potassium hydroxide and (2)
provides better quality adsorption carbon products. At the
beginning of the decoking cycle, the modified pet coke mass is a
semi-solid at a temperature of about 750-850.degree. F. and
pressures of 15 to 50 psig. As discussed in coke hydroprocessing,
the solidified portion of the coke mass demonstrates a significant
degree of carbon adsorption character. Molten anhydrous potassium
hydroxide (M.P.=680.degree. F.) is added to the coke mass until the
voids are essentially filled (or less depending on desired
conversion levels). The quantity of potassium hydroxide in an
exemplary embodiment may be 10 to 150 wt. % (preferably 40-80 wt.
%) of the initial coke weight. After sufficient residence time 0.25
to 6 hours (preferably 0.5-2 hours), the potassium hydroxide (KOH)
and reaction products are drained to the KOH recovery system. The
residual KOH is stripped form the pet coke by steam and sent to the
KOH recovery system. The KOH recovery system separates the
potassium hydroxide from the reaction products and recycles the
activation agent (KOH). The pet coke is further cooled and cut from
the drums as described in the current invention.
[0839] Other embodiments of this chemical extraction method would
include the following:
[0840] 1. Treat modified pet coke with phosphoric acid and/or
steam; 750-1110.degree. F. in rotary kiln.
[0841] 2. Pyrolysis oxidation of modified pet coke; followed by
treatment with nitric acid.
[0842] 3. Other activation agents with preferable chemical
properties, physical properties, and/or costs.
[0843] 6. Uses of Improved Pet Coke Adsorption Characteristics.
[0844] The improved adsorption characteristics of the modified coke
in the current invention provide greater opportunity to further
enhance its fuel qualities and carbon adsorption properties.
Various adsorption and impregnation techniques can uniformly add
various chemical agents to the internal pores of the modified pet
coke. These chemical agents can be used to (1) reduce sulfur oxide
emissions from the pet coke combustion, (2) improve combustion
characteristics of the modified pet coke, and (3) enhance carbon
adsorption characteristics for use of the modified pet coke in
various carbon adsorption and catalyst applications. These same
adsorption and impregnation techniques could also be applied to
unmodified pet coke (e.g. anode-grade sponge coke from sweeter
crudes). However, the success of such applications can be limited
due to less carbon adsorption character. In addition, these
adsorption and impregnation techniques can also be applied to other
porous, carbonaceous materials. Greater success (vs. unmodified pet
coke) can be attainable, particularly with activated carbon
materials or carbon-based catalysts.
[0845] A. Coke Adsorption and/or Impregnation with Sulfur
Reagents
[0846] As noted earlier, certain chemical agents can be uniformly
added to the petroleum coke to mitigate the problems associated
with high sulfur levels in the modified petroleum coke. These
impregnated chemical agents (e.g. sorbents) scavenge the coke
sulfur in the combustion process and convert the sulfur to sulfur
compounds, which are solid particulates at the flue gas temperature
of particulate control devices (i.e. existing or otherwise). In
this manner, the fuel's sulfur can be collected in innocuous sulfur
compounds in the combustion systems' existing (or modified or new)
particulate control device, instead of being emitted to the
atmosphere as sulfur oxides (SOx). The conversion of sulfur oxides
to particulates that are collectible in the existing particulate
control device is similar to dry sorbent scrubbing technology
(prior art). On the other hand, the integration of chemical agents,
such as SOx sorbents, into the very porous crystalline structure of
the modified coke is conceptually similar to the impregnation of
activated carbon (prior art). However, this impregnation of the
modified pet coke with sulfur reagents (present invention) is an
unique process that provides additional utility and benefits,
including higher sulfur removal efficiencies and/or more efficient
sulfur reagent (e.g. SOx sorbent) utilization.
[0847] (1) Prior Art; Dry Scrubbing & Activated Carbon
Impregnation
[0848] a. Dry Sorbent Scrubbing:
[0849] Various technologies have been developed to remove sulfur
oxides (SOx) from combustion flue gases. The most common are wet
and dry scrubbing technologies. Wet scrubbing technologies use
liquids to absorb gaseous SOx and chemically convert them to
compounds that can be physically removed from the flue gas. In
contrast, dry scrubbing technologies use solids to adsorb the
gaseous SOx and chemically convert them to particulate compounds
that can be readily collected in particulate control devices. The
adsorbing solids are commonly referred to as sorbents. Dry
scrubbing technologies are further classified by the type of
sorbent injection: solids (dry) or slurry (wet). The slurry
injection is currently capable of higher SOx removal efficiencies,
but requires higher reaction times at lower temperatures with
higher capital and operating costs. Sorbent injection of dry solids
is the scrubbing technology that is most similar to the present
invention, and is discussed below in greater detail.
[0850] Various chemical compounds containing alkali metals and
alkaline earth metals (Periodic Table Groups IA and IIA) have been
used as dry sorbents to remove sulfur oxide emissions from the
exhaust gas of combustion systems. Three primary types of dry
sorbents are as follows:
[0851] 1. Calcined Lime (CaO) convert SOx to CaSO.sub.4 at
temperatures of 1600-2300.degree. F.
[0852] 2. Hydrated Lime (Ca(OH) 2) converts SO.sub.2 to Ca SO.sub.3
at <1020.degree. F down to saturation.
[0853] 3. Sodium Carbonates convert SOx to Na.sub.2SO.sub.4 at
temperatures of 275-400.degree. F.
[0854] Typically, the sulfur oxides (SOx) are first adsorbed and
then chemically converted to chemical compounds. The sulfur-bearing
compound is normally inorganic and a dry, particulate at the
temperature of the particulate control device. Thus, the sulfur
bearing particulate is collected and the sulfur oxide emissions are
reduced. The overall reduction of sulfur oxide emissions is
primarily dependent on (1) sorbent type and amount (i.e. sorbent
stoichiometric ratios), (2) injection temperature and thermal
profile of the combustion process, (3) sorbent calcine surface
area, (4) sorbent particle size, (5) initial SOx level, and (6)
associated reaction equilibrium and reaction kinetics, including
associated limitations.
[0855] The following limitations often hinder favorable reaction
kinetics (e.g. calcium sorbent):
[0856] 1 . Bulk diffusion of SOx to the sorbent particle (e.g.
CaO)
[0857] 2. Diffusion of SOx through the pores of sorbent (e.g.
CaO)
[0858] 3. Diffusion of SOx through the layer of converted sulfur
compound (e.g. CaSO.sub.4)
[0859] 4. Filling of the small pores causing a decrease in reactive
area
[0860] 5. Buildup of converted sulfur compound (e.g. CaSO.sub.4) at
pore entrances causing pore closures
[0861] 6. Loss of surface area due to sintering (i.e. high
temperature exposure)
[0862] 7. Reduced kinetic reaction rates at low temperatures
[0863] Consequently, equilibrium is seldom achieved and greater
stoichiometric ratios are required to overcome these limitations to
achieve higher SOx removal efficiencies. Sorbent to sulfur ratios
on the order of 1.5-2.0 are usually required to achieve SOx removal
efficiencies >50%.
[0864] The point(s) of sorbent injection is also a major factor in
determining SOx removal efficiency. As noted above, each type of
sorbent has an ideal temperature window to react with the sulfur
oxides (i.e. SOx). As such, injection of the sorbent upstream of
this temperature window is necessary to allow ample mixing time and
reaction time in these temperature zones. For example, calcined
lime (CaO), derived from various possible sorbents, typically
requires a temperature window about 1600 to 2300 degrees Fahrenheit
(.degree. F.). Thus, injection in the furnace is desirable.
Injection temperatures typically range from 1800 to 2700.degree. F.
However, high flame temperatures, particularly at temperatures
>2500.degree. F., can sinter the sorbent's crystalline
structure. Sintering normally decreases reactive sorbent surface
area and access to it. In fact, mixing pulverized, calcium sorbents
(e.g. limestone) with solid fuels has been tried with lower SOx
removal effectiveness due to severe sintering in the high
temperature flame zones. Consequently, a separate system is
normally required to inject SOx sorbents downstream of the
high-temperature, flame zones. Unfortunately, more than one
injection point is often necessary to inject the sorbents into the
proper temperature window for different boiler loads. That is, one
injection point often has significantly different temperatures for
different boiler loads, reducing sorbent effectiveness and average
SOx removal.
[0865] b. Impregnation of Activated Carbon:
[0866] Activated carbons have been impregnated with various organic
or inorganic chemicals for three primary reasons:
[0867] (1) Optimization of Existing Properties of Activated Carbon:
Catalytic oxidation of organic and inorganic compounds is one
example of an existing property of activated carbon. Impregnation
of the activated carbon with potassium iodide can promote
additional/controlled oxidation and optimize this property. Other
examples also exist.
[0868] (2) Synergism Between Activated Carbon and Impregnating
Agent: Activated carbon and sulfur is one example of such
synergistic effects of the sulfur impregnating agent for the
efficient removal of mercury vapors from gases at low temperatures.
Other types of synergism exist.
[0869] (3) Use of Activated Carbon as an Inert Carrier Material.
The impregnation of phosphoric acid on activated carbon for ammonia
removal is an example of activated carbon as an inert porous
carrier material. In this case, the internal surface of the
activated carbon adsorbs the ammonia at certain reaction sites. The
weak Van der Waals forces of adsorption allow the ammonia molecules
to migrate along the internal surface of the carbon to the
phosphoric acid's reaction sites. The ammonia then reacts with the
phosphoric acid to form ammonium phosphate. This two-step reaction
mechanism is commonly referred to as chemisorption.
[0870] The manufacture of impregnated activated carbons is achieved
by two basic methods: soaking impregnation or spray impregnation.
Soaking impregnation consists of soaking an activated carbon of
suitable quality with solutions of salts or other chemicals. In the
spray impregnation, the suitable activated carbon is sprayed in a
rotary kiln or in a fluidized bed under defined conditions. In
either case, the wet, impregnated activated carbon needs to be
dried in an appropriate drier (e.g. rotary kiln or fluidized bed
drier). In some applications, the impregnating agents are present
as hydroxides, carbonates, chromates, nitrates, or other complex
ion forms. In these cases, the impregnating agent must be subjected
to thermal treatment at temperatures of 300 to 400 OF to decompose
the anions. After drying and/or other post-impregnation treatment
steps, the desired impregnating agent remains on the internal
surface of the activated carbon.
[0871] Limited and homogeneous distribution of the impregnating
agents on the internal surface of an activated carbon is important.
In addition, blocking of macropores, mesopores, and micropores
should be avoided in order to keep the impregnation agent
accessible for the adsorbed reactants. Though impregnation agents
are typically up to 30 wt. % of the impregnated activated carbon,
the impregnating agent is predominantly distributed in the
micropore system with minimal pore blockage in many types of
successful impregnation. For example, activated carbon has been
successfully impregnated with 15 wt. % sulfur with a fairly uniform
distribution of sulfur in a monomolecular layer on the internal
surface of the activated carbon. The impregnation only reduced the
micropore system's surface area from 742 to 579 m.sup.2/g. In this
manner, the sulfur-impregnated activated carbon not only removes
mercury via sulfur chemisorption, but also provides substantial
adsorptive removal of other gas impurities. Similarly, other
impregnated activated carbons can achieve limited, homogeneous
distribution of up to 30 wt. % impregnating agent, predominantly in
the micropore system, without plugging vital passage ways
throughout the activated carbon's pore systems.
[0872] (2) Present Invention; Adsorption/Impregnation of Modified
Pet Coke; Sulfur Reagents:
[0873] Unlike the prior art, the present invention incorporates
sulfur reagents (e.g. sorbents) in the fuel, providing superior
performance and substantial advantages over the prior art. That is,
the present invention can integrate these various types of reagents
for sulfur removal within the porous crystalline structure of the
modified petroleum coke. In so doing, any sulfur reagents are
generally shielded from the high flame temperature (i.e. sintering)
until the petroleum coke char is oxidized. In this manner, the
desired reagent crystalline structure is maintained to achieve
higher sulfur removal efficiencies and, in many cases, eliminate
the need for a separate sorbent injection system. Furthermore, the
monomolecular to di- or tri-molecular layers of sorbents are less
prone to the detrimental effects of sintering due to less blockage
of reactive sorbents with altered sorbent crystalline structure. At
the same time, several of the reaction kinetic limitations of the
prior art are substantially reduced to improve the sulfur removal
efficiency and/or increase efficiencies of reagent utilization
(i.e. lower stoichiometric ratios). The integration of these
chemical reagents into the porous structure of the modified
petroleum coke is the key. Similar to the soaking impregnation of
activated carbon, the aqueous coke quench solution carries the
desired reagents into the macropores, mesopores, and micropores of
the pet coke in the quench cycle of the coking operation. This
novel process of impregnating the highly porous, modified pet coke
can be summarized in (1) selection of appropriate sulfur
reagent(s), (2) preparation of the coke quench solution, (3)
modification of quench cycle in coking operation, (4) impacts of
pet coke pulverization, and (5) the performance of reagents in the
combustion of the modified pet coke.
[0874] a. Selection of Appropriate Sulfur Reagents:
[0875] The selection of optimal sulfur reagents (including
traditional SOx sorbents of the prior art) for a particular
application is dependent on many factors; primarily reactivity,
selectivity, temperature sensitivity, resistance to sintering,
solubility, and costs. As noted above, traditional SOx sorbents are
generally selected from the class of inorganic compounds that
contain alkali metals and/or alkaline earth metals (Periodic Table
Groups IA and IIA). However, the present invention should not be
limited to these compounds, but also include any other chemical
compound that readily reacts with sulfur (with or without
adsorption) and forms particulate compound(s) that is readily
collected from the flue gas stream.
[0876] Evaluation of the optimal sulfur reagent can vary
significantly for each combustion application. The sulfur reagents'
reactivity, selectivity, temperature sensitivity, and resistance to
sintering all relate to the reagent's ability to efficiently
convert primarily sulfur to collectible compound(s). The reagent's
effectiveness and desirability depend on the required sulfur
removal and the temperature profile under various loads for the
specific combustion system. In many cases, the sulfur reagent's
resistance to sintering is not a major factor due to the coke char
insulation of the reagent crystalline structure in the current
invention. However, this mechanism of sintering prevention, can
vary substantially in different combustion applications due to
firebox/burner design and operation. That is, the need for timely
coke char burnout in firebox hot zones (e.g. >2300.degree. F.)
and the required particle size distribution of the modified pet
coke can make this more difficult to achieve in some cases.
Consequently, the reagent's resistance to sintering can become a
significant factor, considering this reagent injection in the fuel.
However, as noted earlier, the detrimental sintering effects are
substantially reduced form the prior art due to the relatively
minor thickness (i.e. layers with <5 sorbent molecules thick;
preferably I sorbent molecule thick) of the sorbents within the pet
coke pores.
[0877] In addition, solubility characteristics and costs of
different sulfur reagents can also vary significantly for each
refinery coker application. The required solubility characteristics
is dependent on the coker's coke quench characteristics and process
requirements. The costs can vary significantly with the required
quantity of reagent for desired sulfur removal and the required
preparation of the coke quench solution. The delivered price of
various reagents can vary, particularly in relation to reagent
source proximity and types of transportation available.
[0878] Overall, the preference rank of sulfur reagents is generally
the same among different applications. However, all of these
factors can vary significantly for different applications,
particularly cost. Consequently, these factors must be considered
in each application, and the optimal sulfur reagent selected
accordingly. One skilled in the art can evaluate these various
factors to determine the optimal reagent for a particular
application.
[0879] b. Preparation of Coke Quench Solution:
[0880] The preparation of coker quench solution primarily involves
the addition of the sulfur reagent of choice to the quench water of
the coking cycle. The water solubility of the chosen reagent is a
primary consideration. For example, sulfur reagents containing
alkali metals (Periodic Table Group IA) are generally highly
soluble in water. In contrast, sulfur reagents containing alkaline
earth metals (Periodic Table Group IIA) usually have limited
solubility in water. Ideally, the desired quantity of reagent (i.e.
reagent/sulfur ratio) can be added to the modified pet coke via a
sub-saturated, saturated, or supersaturated solution of the reagent
in the quench water. Alternatively, a saturated solution of reagent
with suspended reagent solids in the quench water can be used, as
long as the reagent is pulverized to the smallest practical size
distribution (e.g. 95% <4 microns) feasible.
[0881] The coker reagent/quench solution primarily depends on the
required quantity of reagent to achieve the desired SOx removal,
the reagent's solubility, and the quantity of quench solution
required by coker process needs. In most cases, keeping the
quantity of quench solution relatively constant is desirable. In
some cases, however, increasing the quantity of quench solution may
be desirable to decrease the required amount of suspended reagent
solids in a saturated quench solution. One skilled in the art can
readily determine the proper quantity of reagent based on desired
reagent/sulfur ratios. Furthermore, one skilled in the art can
determine the desired quantity of quench solution based on coker
process requirements, reagent solubility, and process equipment
capabilities. In cases using saturated solutions with suspended
reagent solids, the reagent should be pulverized to the lowest
practical size distribution (e.g. <4 microns; preferably <2
microns) to promote integration into mesopores and macropores and
minimize plugging of pores. It should be noted that the quench
solution in many cokers already contain sludges from other refinery
processes without significant plugging problems. These sludges
often contain suspended solids with solid particles >75 microns
(or micrometers).
[0882] c. Modification of Coker Quench Cycle:
[0883] The quench cycle of the coking operation provides the
mechanism to impregnate the porous, modified pet coke with sulfur
reagents. Whether saturated, supersaturated, sub-saturated, or
saturated with suspended reagent solids, the quench solution is
pumped through the solidifying coke mass in a manner that is very
similar to the current quench cycle. This quenching process forces
the quench solution under high pressure through the internal pores
of the modified pet coke, and provides significant advantages over
most methods used to impregnate activated carbon. However, some
slight modifications may be necessary to accommodate any excessive
suspended reagent solids and potential for plugging. One skilled in
the art can determine the need for modifications of equipment or
process parameters, based on equipment and process
specifications.
[0884] As the quench solution passes through the hot, solidifying
coke mass (temperatures>solution boiling point at process
conditions), most of the water in the aqueous quench solution
evaporates and leaves the desired reagent integrated in the pet
cokes crystalline structure. Similar to crystallization from
solutions, initial evaporation of the quench solution will create a
supersaturated solution of the reagent. Nucleation (via coke
crystals or otherwise) is expected to induce reagent crystal growth
on the pet coke surface at a molecular scale (e.g. <2
nanometers). Similar to the impregnation of activated carbon,
molecular layers of reagent can be uniformly deposited on a limited
amount of internal surface area (predominantly micropores). These
molecular layers are typically less than 5 reagent molecules thick
(preferably 1 molecule thick). In this manner, the reagent can be
deposited somewhat uniformly in the macropores, mesopores, and
preferably micropores of the modified petroleum coke of the current
invention. Again, by definition, these pores have the following
rough diameter sizes: macropores>50 nm (nanometers); mesopores=2
to 50 nm; and micropores<2 nm.
[0885] A saturated solution (or slightly sub-saturated solution) of
sulfur reagent should be continually used for further cooling and
coke cutting. After the coke has cooled sufficiently and quench
water evaporation no longer occurs (temperatures <solution
boiling point at process conditions), the saturated (or
sub-saturated) quench solution for further cooling avoids excessive
leaching of the reagent from the internal surface of the coke (i.e.
reagent solubility in non-saturated quench solution). For the same
reason, a saturated solution (or slightly sub-saturated) should
also be used for the cutting water that cuts the coke from the coke
drum.
[0886] After cutting the coke from the drum, some of the reagents
deposited on the macropore walls will become part of the external
surface of the coke chunks (preferably diameter=6-24 inches). This
potentially exposes these reagents to weathering during transport.
The resistance to water flow through the internal pores at ambient,
atmospheric conditions limits weathering effects to mostly the
external surface. In contrast, most of the reagents deposited in
micropores, mesopores, and some macropores will still be part of
the internal surface of the coke chunks. The proportion of each
will depend on the coke crystalline structure and the type/degree
of coke cutting. That is, the internal surface area increases as
the porosity of the sponge coke increases with predominantly
micropores and mesopores. The greater the internal surface area,
the greater the protection of the reagent from weathering and high
flame temperatures (discussed later). This further emphasizes the
utility of the process options of the current invention for
increasing the pet coke porosity beyond traditional sponge coke
porosity, if necessary.
[0887] d. Impacts of Pet Coke Pulverization:
[0888] The pulverization of the modified pet coke can affect the
reagent utilization. In many applications, the modified petroleum
coke will normally be pulverized at the end-user's facility
immediately prior to combustion. In these cases, additional reagent
will normally be exposed to the flame zone on the external surface
of the coke. The quantity of reagent exposed in this manner is
primarily dependent on the pet coke crystalline structure and the
type/degree of pulverization. As noted previously, the deposition
of reagent is predominantly in the micropores in many cases
(similar to impregnation of activated carbon). Also, the pet coke
crystalline structure can be controlled, to a certain degree, by
the process options of the current invention. The type and degree
of pulverization depends on the pulverizers and combustion
requirements at the end-user's facility. Again, as noted earlier,
the detrimental sintering effects are substantially reduced form
the prior art due to the relatively minor thickness (i.e. layers
with <5 sorbent molecules thick; preferably 1 sorbent molecule
thick) of the sorbents within the pet coke pores.
[0889] For example, pulverization can range from >60 to >95%
passing through 200 mesh (i.e. <75 microns), depending on the
particle size distribution required to complete combustion before
the furnace exit. This depends on the combustor's design and
operation, the fuel mix, and the combustion characteristics of the
modified petroleum coke. During pulverization, some of the sulfur
reagent may actually be separated from the modified pet coke, but
most should remain with the fuel. In many cases, the molecular
nature of the sulfur reagent will substantially reduce the impact
of exposure to high flame temperatures in the combustion process.
That is, the detrimental effects of sintering are greatly reduced
because the amorphous crystalline layer of sintering limits access
to only a few molecular layers, if at all. In contrast, sintering
of larger particles (e.g. 1-40 microns) in the prior art can block
a much higher percentage of internal reactive surfaces of the
larger sorbent crystalline structures.
[0890] e. Performance of Reagents in the Combustion of the Modified
Pet Coke:
[0891] During the combustion of the modified pet coke, the sulfur
reagents in the coke crystalline structure react with the fuel
sulfur in a manner that normally increases the prior art's SOx
reduction for a given sulfur reagent/sulfur ratio. The improved
performance is attributed to a combination of factors, including
(1) reduced sintering effects, (2) improved reaction mechanisms,
and/or (3) reduced kinetic reaction limitations (vs. the dry
sorbent scrubbing of the prior art).
[0892] As noted in the prior art discussion, sintering is a primary
cause for the reduction of SOx removal and sorbent utilization
efficiencies in the prior art. That is, sintering effectively
changes the sorbent crystalline structure, reducing porosity and
adsorption effectiveness. With the present invention, the impact of
sintering is mitigated by the following primary mechanisms:
[0893] (1) Sulfur reagents can be effectively insulated from the
hot flame by the shelter of the surrounding pet coke char (i.e.
minimal thermal conductivity or high insulating properties of
covalent bonded materials such as polymeric hydrocarbon structure
of pet coke char). For most of the reagent on the internal pores of
the char, this sintering protection is provided until downstream of
the primary flame, where the pet coke char is oxidized and consumed
at flue gas temperatures of 1600-2800.degree. F, (preferably
2100-2300.degree. F.). That is, the devolatilization and the
primary flame zone typically occur in the first 0.01 to 0.10
seconds. In contrast, the char usually is oxidized and consumed
after 1 to 2 seconds. and/or
[0894] (2) The molecular nature of the sulfur reagent substantially
reduces the detrimental effects of sintering. That is, access to
many reactive sorbent molecules deep inside a large crystalline
structure (1-40 microns) are inhibited by sintering in the prior
art. In contrast, the molecular nature of the impregnated reagent
of this invention (e.g. deposited in molecular layers <2
nanometers) severely limits the loss of access to reactive sulfur
reagents due to sintering.
[0895] With limited impact from sintering, the reactive reagents
are more effectively utilized in the conversion of fuel sulfur to
sulfur compounds that are collectible in particulate control
devices. Consequently, sulfur conversion will depend more heavily
on the decomposition or breakdown rate of sulfur compounds within
the coke.
[0896] The sulfur in the petroleum coke is primarily tied up as
thiophenes in heavy hydrocarbons (e.g. aromatics, asphaltenes, and
resins) of the coke char. As temperatures of the coke char exceed
1000.degree. F., the heavy hydrocarbons thermally crack and release
sulfur from tight chemical bonds. The resulting sulfur (or sulfur
compound) tends to oxidize before the fixed carbon of the coke
char. Thus, gaseous sulfur oxides are typically formed prior to the
complete oxidation of the char. In addition, the thermal cracking
and volatilization of the low-quality VCMs (i.e. boiling points
>750.degree. F.) in the modified coke of the current invention
is expected to provide greater mass transfer in the internal pores
and expose reagent layers on the pet coke's surface. Again, VCMs
are Volatile Combustible Materials as defined by ASTM Method D
3175. As a result, sulfur adsorption and conversion can be achieved
by various mechanisms, including:
[0897] (1) Oxidation of coke sulfur compounds to gaseous sulfur
oxides that migrate to the adjacent reagent molecules. SOx adsorbed
by reagent molecule and SOx chemically converted. Adsorption can
take place either within or outside the pet coke particles or
char.
[0898] (2) Similar to chemisorption associated with impregnated
activated carbon, the gaseous sulfur oxides from oxidation of coke
sulfur compounds are adsorbed by the coke crystalline structure and
chemically converted by the sulfur reagent: via migration to
reaction sites.
[0899] (3) Sulfur compounds (not in traditional oxide form) are
released from the breakdown of the coke sulfur compounds. These
sulfur compounds are adsorbed by the pet coke crystalline structure
and chemically converted by the sulfur reagent. This mechanism is
more likely with non-traditional reagents that react with non-oxide
forms of sulfur. And/or
[0900] (4) As the char of the modified coke is oxidized/consumed at
temperatures of 1450-2000.degree. F., unreacted reagent is released
from the coke with substantially less sintering (vs. limestone or
lime mixed with fuel). This unreacted reagent adsorbs and converts
sulfur oxides (from coke or other fuels) in a manner similar to
traditional dry sorbent injection of the prior art.
[0901] In this manner, the present invention not only reduces the
impact of sintering on sulfur reagents in the furnace, but provides
alternative mechanisms of adsorption and chemical conversion to
achieve the desired SOx removal efficiencies.
[0902] The present invention also substantially reduces several of
the kinetic reaction limitations for the sulfur sorbents described
in the prior art: dry sorbent scrubbing:
[0903] (1) Bulk diffusion of SOx to the reagent as a reaction
constraint is greatly reduced. The reactive sulfur reagents are
contained in the pet coke crystalline structure, surrounded by or
adjacent to the area of highest sulfur concentration: the pet coke
itself. Regardless of the adsorption and chemical conversion
mechanism, the sulfur and reagent are in close proximity.
[0904] (2) In general, sulfur reagents of this invention have
substantially smaller particle size distribution (e.g. diameters
<2 nanometers vs. <1-40 micrometers). Thus, kinetic reaction
limitations 2.-5. (described in prior art: dry sorbent scrubbing)
become far less significant. That is, the very small reagent
particles substantially reduce the ratio of sulfur molecules
adsorbed per reagent particle, mitigating concerns of sulfate
layers and pore pluggage.
[0905] (3) Sulfur reagents of the current invention are activated
and/or released in a reactive form well ahead of the desired
temperature window for reagent adsorption and chemical conversion
of sulfur compounds (e.g. sulfur oxides).
[0906] For a given application, the performance of the sulfur
reagents (or sorbents) in the combustion of the modified pet coke
is significantly improved due to any one, a combination, or all of
these factors. Also, the performance of the sulfur reagents can be
further optimized by controlling the pet coke char burnout and the
availability of the sulfur reagents. In turn, the char burnout and
availability of the sulfur reagent can be controlled, to a certain
degree, by the coke particle size distribution, VCM quality, and
VCM content of the modified pet coke. The current invention should
not be limited by the foregoing theories of mechanisms and
operability, but be used as the bases for optimizing the technology
for different types of applications.
[0907] The process options to increase sponge coke porosity and
VCMs beyond traditional sponge coke become more important to
optimize the balance between improving combustion characteristics
and achieving adequate SOx removal. In many cases, these features
will remain congruent and work together. In other cases, however,
these features of this invention need to be optimized to strike a
realistic balance for the individual applications of this
technology. Thus, the current invention should not be limited by
the general theories exposed herein, but encompass the practical
application of this technology to the individual circumstances of
each situation. That is, the general theories can be used as a
guide, but may not specifically apply to all applications. One
skilled in the art can modify the coker process to optimize this
technology for each application and remain in the spirit and intent
of the current invention.
[0908] (3) Exemplary Embodiment; Sox Sorbent=Calcitic Hydrated
Lime:
[0909] In an exemplary embodiment, calcitic hydrate (alias calcitic
hydrated lime, high calcium hydrated lime, or calcium hydroxide
Ca(OH).sub.2) is impregnated on the porous pet coke. This exemplary
embodiment can best be summarized by again reviewing (1) selection
of desired sulfur reagent (e.g., calcitic hydrate), (2) preparation
of the quench solution, (3) modification of quench cycle in the
coking operation, (4) pulverization of the pet coke fuel, and (5)
performance of the calcitic hydrate in the combustion of the
modified pet coke.
[0910] a. Selection of Calcitic Hydrate as Sulfur Reagent:
[0911] In general, calcitic hydrate may be selected as the most
desirable sulfur reagent, primarily due to its low costs, reaction
temperature window, high reactivity, and resistance to sintering.
In this invention, reagents with alkaline earth metals (Periodic
Table Group IA) may be preferable to reagents with alkali metals
(Periodic Table Group IIA) due to higher reaction temperature
windows (800-2600.degree. F. vs. 250-350.degree. F, respectively).
That is, alkali metal reagents added to the modified pet coke may
form less desirable compounds (e.g. sodium vanadates) prior to
reaching the proper temperature window in the combustion system
(i.e. downstream of the economizer). In contrast, the reagents with
alkaline earth metals may be injected via the modified pet coke
into their regions of greatest sulfur reactivity (furnace through
economizer).
[0912] Calcium is generally the alkaline earth metal with the
greatest sulfur reactivity and the lowest cost. Among the calcium
reagents, hydrated limes (e.g. calcitic & dolomitic) have the
highest SOx removal capabilities, primarily due to higher specific
surface areas (10-21 m.sup.2/g vs. <6 m.sup.2/g) than carbonate
forms (e.g. limestone & dolomite). In furnace zones exceeding
2000.degree. F, calcitic hydrate (i.e. Ca(OH).sub.2) derived from
limestone generally calcines/dehydrates with a continual decrease
in surface area; primarily due to sintering. With the reduced
impact of sintering in this invention, the calcitic hydrate has SOx
removal capabilities up to and sometimes exceeding 75% (vs. 60% in
the prior art). In contrast, dolomitic hydrates (Ca(OH).sub.2 with
MgO or Mg(OH).sub.2) calcine with a substantial increase in surface
area in the prior art, and demonstrate higher SOx removal
capabilities. As such, dolomitic hydrates have a greater resistance
to sintering. With the current invention, dolomitic hydrates have
SOx removal capabilities up to 90% (vs. 75% in the prior art).
However, the magnesium in the dolomitic hydrates is usually
chemically inert. Though it improves calcium utilization, the
magnesium can detrimentally impact total ash loading, ash fouling
characteristics, and ash reuse/disposal. In addition, dolomitic
hydrates, particularly the often-preferred dihydrated form, has
significantly higher costs (e.g. production & transportation).
One skilled in the art can evaluate these various factors to
determine the optimal reagent for a particular application. In
general, though, calcitic hydrate may be selected as the desired
reagent due to lower costs, related ash character & loading,
solubility characteristics, and the mitigation of sintering effects
offered by this invention. Consequently, the remaining discussion
of the exemplary embodiment will examine the impregnation of
calcitic hydrate on the pet coke.
[0913] b. Preparation of Coke Quench Solution:
[0914] The preparation of coker quench solution involves adequate
addition of calcitic hydrate to the quench water for the decoking
cycle. This can be accomplished by various means, including (1) the
direct addition of commercially available calcitic hydrate or (2)
the addition of commercial calcitic lime (i.e. quick lime CaO) that
partially or fully converts to the hydrated form. Commercial
calcitic hydrate is normally prepared from hydration of calcitic
lime with particle agglomeration before shipment. Generally, the
calcitic hydrate is 72-74 wt. % calcium oxide (CaO) and 23-24 wt. %
percent chemically combined water. Either approach can be
accomplished on-site (i.e. at the coker) with additional equipment
for storage, mixing, settling, etc. The latter approach, completed
on-site, may generally be preferred due to lower costs, potential
use of the high heat of solution, and the development of a finer
crystalline structure. That is, the hydrated form of the second
approach (e.g. without agglomeration) tends to have a crystalline
form with finer particle size than typical commercial production of
calcitic hydrate from quick lime. However, insufficient purity of
calcitic hydrate (vs. a combination of calcitic hydrate and
calcitic lime) is a potential drawback of the second approach.
However, in some cases, this combination can be preferable, if the
calcitic lime is uniformly deposited on the pet coke internal pores
without the additional water of the hydrated form.
[0915] In either approach, the quench solution becomes a saturated
or sub-saturated solution of calcitic hydrate (i.e. Ca(OH).sub.2)
in water. The saturated solution is preferable (vs. suspended
solids of pulverized calcitic hydrate) to maximize molecular
deposition of calcitic hydrate in the mesopores, macropores and
preferably micropores of the modified pet coke and to greatly
reduce pluggage of any pores. The saturated quench solution can be
used in the following cases: (1) low to medium coke sulfur levels
(e.g. <4.0 wt. %), (2) low to medium SOx removal required (e.g.
<50%), and/or (3) high water quench rates (e.g. >200
gallons/ton of coke). Items (1) and (2) relate to the mass of
calcitic hydrate required (i.e. stoichiometric ratio of Ca/S
required to achieve a desired SOx removal level). The Ca/S ratio of
the current invention ranges from 0.1 to 4.0 (preferably 0.5 to
2.0) to achieve SOx removal levels up to and exceeding 75%. Item
(3) refers to the quantity of quench water available to incorporate
the required calcitic hydrate within solubility limits (i.e.
saturated or sub-saturated solution). Since the current invention
promotes increasing coke VCM, water quench rates can be increased
by reducing quantities of steam at the beginning of the decoking
cycle to strip out trapped hydrocarbon liquids and initiate coke
cooling.
[0916] For example, a coker currently produces 1000 ton/day of pet
coke with 4.0% sulfur. The utility boiler requires <50%
reduction in the SOx of the pet coke portion of the coke/coal
blend. If the Ca/S stoichiometric ratio required to achieve this
level is 1.5, the daily amount of calcitic hydrate required in the
pet coke is roughly 277,500 pounds
(1000.times.2000.times.0.04.times.74/32.times.1.5). At atmospheric
pressure, the solubility of calcitic hydrate in pure water is
roughly 0.165 grams/cc at 20.degree. C. and 0.077 g/cc at
100.degree. C. This translates to approximately 1.4 lb./gallon and
0.6 lb./gallon, respectively. The saturated quench solution that is
totally evaporated in the quench process deposits all of the
calcitic hydrate in solution (i.e. 1.4 lb./gal.) on the internal
pores of the modified coke. The saturated quench solution that
finishes the coke cooling without evaporation will deposit
additional calcitic hydrate (e.g. 0.8 lb./gal. =1.4-0.6) due to
calcitic hydrate's lower solubility at the elevated temperature
(.about.100.degree. C). If 80% of the saturated quench solution is
evaporated in coke cooling, roughly 216,800 gallons (i.e. 173.4
Mgals. evaporated & 43.4 Mgals heated) of saturated quench
solution would be required each day. If higher quench water rates
are used for process needs (e.g. 200 gal/ton of coke vs. 173.4),
the quench solution can be sub-saturated. In addition, the actual
solubility for each application will need to consider the effects
of process cooling requirements, process temperatures, process
pressures, and local water conditions. If necessary, certain
chemical agents can be added to the water to increase the
solubility of the calcitic hydrate in water. One skilled in the art
can make these adjustments in quench solution preparation for each
coker application.
[0917] c. Modification of Coker Quench Cycle:
[0918] In the coker quench cycle, the saturated solution of
calcitic hydrate serves as the quench water and provides the
mechanism to impregnate the porous, modified petroleum coke with
calcitic hydrate. As noted previously, steam stripping (i.e. "steam
out") may be reduced to keep more VCM on the coke and allow more
water (vs. steam) for cooling the coke. In fact, the saturated
calcitic hydrate solution is expected to have a significantly lower
vapor pressure than the normal quench water. This can effectively
elevate the vaporization temperature of the quench water: allowing
earlier use of quench water (vs. steam) without causing excessive
pressure buildup in the coke drums. As noted previously, the
saturated quench solution is pumped through the solidifying coke
mass in a manner that is very similar to the current quench
cycle.
[0919] As the calcitic hydrate quench solution passes through the
hot, solidifying coke mass (temperatures>solution boiling point
at process conditions), most of the water in this aqueous quench
solution evaporates and leaves the desired calcitic hydrate
integrated in the pet cokes crystalline structure. That is,
molecular layers of calcitic hydrate are deposited on the internal
surface of the pet coke, preferably in micropores and mesopores.
After the coke has cooled sufficiently (temperatures>solution
boiling point at process conditions), evaporation of the quench
solution stops. However, the saturated solution of the calcitic
hydrate continues to deposit calcitic hydrate on the coke surface
due to lower solubilities at elevated temperatures. In this manner,
much of the calcitic hydrate is uniformly deposited on coke surface
in layers <5 molecules thick (preferably 1 molecule thick). That
is, the use of a saturated solution provides deposition at the
molecular level (e.g. 0.5 to >10 nanometers). In contrast,
larger crystalline particle sizes (e.g. 1 to 4 microns or 1000 to
4000 nm) are associated with suspended calcitic hydrate solids or
the traditional addition of pulverized sorbent in the prior art.
Thus, most of the calcitic hydrate reagent is deposited in the
micropores and mesopores as well as the macropores. However, this
invention should not be limited by this theory of operation.
[0920] While cutting the coke from the coke drums, a saturated
solution of the calcitic hydrate should be used for cutting water.
This avoids leaching of the calcitic hydrate from the internal
surface of the coke due to calcitic hydrate solubility in a
non-saturated cutting solution. After cutting from the drum,
reagent may be exposed to weathering during shipment and storage.
However, rainwater will primarily wash off reagent on exterior
surface due to resistance to flow in the micropores and mesopores.
Either weather protection or the addition of sufficient calcitic
hydrate is needed to offset this potential problem.
[0921] d. Impacts of Pet Coke Pulverization:
[0922] Pulverization of the modified petroleum coke can expose
significant amounts of the calcitic hydrate to flame temperatures.
In traditional sorbent injection of the prior art, high temperature
exposure causes sintering of calcitic hydrate, that reduces SOx
removal effectiveness. However, sintering is a phenomenon that
primarily affects large crystal structures: reactive sorbent is
sealed in the crystalline structure due to blockage of access via
sintering. Sintering is not expected to be a major factor in the
current invention due to the molecular nature of the calcitic
hydrate. That is, amorphous crystalline change of the calcitic
hydrate, which is one to several molecules thick, does not
significantly affect access to unreacted reagent. Thus, sintering
is expected to have substantially less impact on the calcitic
hydrate exposed to flame temperatures as a molecular coating of the
external coke surface in the current invention. However, this
theory of operation should not hinder or limit the patentability of
this current invention.
[0923] e. Performance of Calcitic Hydrate in the Combustion of the
Modified Pet Coke:
[0924] During the combustion of the modified pet coke, the
impregnated calcitic hydrate transforms to a more reactive calcitic
lime (CaO). Throughout the various stages of combustion, the
modified pet coke of the current invention effectively (1) protects
the lime's reactive surface area, (2) reduces the traditional
kinetic reaction limitations of dry scrubbing in the prior art, and
(3) provides an exemplary reaction environment with additional
reaction mechanisms. As a result, the impregnated calcitic hydrate
normally achieves a significantly higher reduction of sulfur oxides
than dry scrubbing in the prior art for a given calcium/sulfur
ratio.
[0925] In the initial stage of combustion, the modified pet coke of
the current invention protects the impregnated calcitic hydrate
from high flame temperatures, mitigating sintering effects. In a
conventional pulverized coal burner, the pulverized pet coke, like
coal, is pneumatically conveyed via primary combustion air through
the coal nozzle of the burner into the hot furnace. In the first
0.01 seconds, the hot furnace temperatures vaporize inherent
moisture and devolatilize the high quality VCMs (e.g. boiling point
<750.degree. F.) in the modified pet coke. These gases (i.e.
steam and vaporized hydrocarbons), exiting the coke pores, tend to
prevent diffusion of hot gases from the primary flame into the
coke's internal pores. The devolatilized VCMs are oxidized in the
first 0.10 seconds, burning in the primary flame zone. As noted
previously, the current invention mitigates detrimental effects of
sintering due to (1) protection from exposure to hot flame zones
via surrounding coke char with good insulation properties and/or
(2) molecular nature of the calcitic hydrate layer on the internal
surfaces of the modified pet coke. The remainder of the petroleum
coke is the pet coke char, including its polymeric crystalline
structure (e.g. heavy aromatic hydrocarbons and fixed carbon),
calcitic hydrate, sulfur, and minimal ash.
[0926] The pet coke char's rate of oxidation is a key factor in the
adsorption and chemical conversion of pet coke sulfur. The pet coke
char undergoes various reactions over the next 1-2 seconds. As
expected, the char oxidation and higher temperatures predominantly
initiate on the external surface and work inward. The char
oxidation rates primarily depend on local temperature, oxygen
diffusion, particle size, and char reactivity. As the local
temperature of the internal coke char increases, furnace
temperatures of combustion products (i.e. flue gas) decrease. The
oxidation of pet coke char often occurs at local temperatures of
950-1600.degree. F. The external surfaces of the pet coke char are
closer to flue gas temperatures of 3000-3200.degree. F. just after
the primary flame. In many pulverized coal boilers, this flue gas
temperature decreases to 1700-2000.degree. F. at the superheater
tubes. At the higher temperatures, mass transfer of oxygen to the
coke char particle is normally the rate-controlling step, in most
cases. Thus, oxidation of the pet coke char is minimal in the
primary flame zone due to predominant oxygen consumption by
vaporized VCMs. After this primary flame zone, char with larger
particle size (>30 microns) and/or high mass-to-surface area
heat up more slowly and oxidize less quickly. Also, larger char
particles tend to lose mass before volume due to the formation and
loss of carbon monoxide and carbon dioxide from internal pores.
This phenomenon indicates oxygen diffusion into the internal pores
prior to total oxidation of the external surface. In addition,
activated carbons are capable of catalytic oxidation of organic and
inorganic compounds. That is, the oxygen molecules are adsorbed on
the activated carbon surface and broken into very reactive
radicals. This oxygen activation by the activated carbon is the
actual catalytic step. Similarly, the modified coke of the current
invention, can adsorb and activate oxygen molecules. The resulting
oxygen radicals will tend to react with the sulfur ions or
compounds within the coke pores at a significantly lower
temperature than traditional sulfur combustion. Consequently, the
pet coke char's rate of oxidation can be effectively controlled by
the pet coke's particle size distribution. This is usually
controlled by the design and operation of the end-user's
pulverization equipment. However, a larger coke particle size
distribution can increase the amount of unburned carbon and
decrease combustion efficiency. Therefore, a realistic balance must
be achieved between the need to complete char oxidation before the
furnace exit and the desire to maintain a conducive environment for
SOx conversion and removal.
[0927] After the primary flame zone, the pet coke char provides a
reaction environment that promotes the adsorption and conversion of
the pet coke fuel sulfur. At temperatures of about 1070.degree. F,
the calcitic hydrate loses water and transforms to calcitic lime
(alias calcium oxide: CaO) with more reactive crystalline
structure. This delayed release of water and its evaporation are
expected to help moderate local temperatures and further mitigate
sintering effects. The fresh crystallization of calcium oxide
mostly occurs prior to breakdown of sulfur compounds and the
oxidation of the surrounding coke char. As temperatures of the coke
char exceeds 1100.degree. F., most of the heavy hydrocarbons
thermally crack and release sulfur from tight chemical bonds. The
resulting sulfur (or sulfur compound) tends to readily oxidize
significantly before the fixed carbon, heavy hydrocarbons, or
carbon monoxide from the pet coke char. Thus, gaseous sulfur oxides
are typically formed sufficiently prior to the complete oxidation
of the char. As a result, adsorption and conversion of sulfur (e.g.
sulfur oxides to calcium sulfate) can preferably take place, while
the calcium oxide is still in the protective environment of the pet
coke char. As discussed previously, this reaction environment
within the internal pores greatly reduces the kinetic reaction
limitations of the prior art due to the close proximity of the
reactants and the molecular nature of the calcium oxide. That is,
diffusion of SOx to the calcium oxide particle, through its pores,
and through any calcium sulfate layers are normally not reaction
rate limiting steps due to their concentrated presence in the coke
pores. Similarly, the prior art's blockage and filling lime pores
by the calcium sulfate is less prohibitive. In addition, the
thermal cracking and the volatilization of low quality VCMs (e.g.
boiling point >750.degree. F.) are expected to provide greater
mass transfer in the internal pores and expose CaO layers on the
modified coke's surface.
[0928] All four of the reaction mechanisms (described above) can
apply in this exemplary embodiment. Reaction mechanisms 1, 2, and 4
will likely predominate with the following primary reaction step in
each: (Note: reaction can use either sulfur dioxide or sulfur
trioxide).
CaO+SO.sub.2+1/2O.sub.2=CaSO.sub.4; where SO.sub.3 can replace
(SO.sub.2+1/2O.sub.2)
[0929] The desired temperature window for sulfur adsorption and
this chemical conversion of sulfur oxides to calcium sulfate is
1600.degree. F.-2300.degree. F. Fortunately, the oxidation of the
coke char is expected to occur in a similar, but slightly higher
range of local temperatures. In some cases, the temperature range
may be significantly different, depending on char particle size and
the furnace design and operation. In most cases, the adsorption and
conversion of the sulfur compounds will occur near the outer
boundary of coke char particle. That is, the diffusion of oxygen to
the internal pores, as well as local temperatures will be greater
near the exterior surface. Since oxygen diffusion will likely be
limiting, the oxidation of the sulfur compounds, adsorption and
conversion to calcium sulfate can take place before, during, or
after complete oxidation of the adjacent coke structure.
Preferably, the majority of the sulfur will be converted to a
stable calcium sulfate form prior to local char oxidation. In
traditional combustion of high sulfur coal, calcium sulfate is
noted to be thermochemically unstable at temperatures
>2300.degree. F. This is apparently due to competing reactions
in this reactive, high sulfur environment. However, if most of the
pet coke sulfur is converted to calcium sulfate prior to complete
coke char oxidation, the high sulfur environment will not likely
exist outside the coke char, where furnace temperatures can exceed
2300.degree. F. Similarly, the destabilizing environment will not
likely exist when the pet coke is used as a blending fuel with low
sulfur coals. In the worst case scenario, the calcium sulfate will
be released into furnace temperatures >2300.degree. F. (early
stages of coke char oxidation or otherwise). In this worst case,
the sulfur in the calcium sulfate will likely break apart and react
with other compounds or remain as SOx. If it reacts to form another
sulfur salt, it can likely be collected in the particulate control
device. If it remains as SOx, unreacted lime (CaO) from oxidation
of coke char near the furnace exit can react at temperatures
1600-2300.degree. F. to form calcium sulfate by the same reaction
mechanism as dry scrubbing of the prior art. In either event,
removal of this sulfur can still occur with downstream particulate
control.
[0930] As the char of the modified coke is oxidized and consumed,
excess, unreacted lime (CaO) is released from the coke with
substantially less sintering (vs. lime or limestone mixed with
fuel). The excess of unreacted calcitic lime is reflected in the
calcium/sulfur ratio, adjusted for the SOx removal achieved. As
discussed previously, most oxidation of the petroleum coke char
occurs at local temperatures of 950-1600.degree. F. Coke char
oxidation is initiated on the external surface in regions of high
flue gas temperatures of .about.3000.degree. F. The coke char
oxidation is normally completed in flue gas temperatures down to
1700.degree. F. Thus, unreacted calcitic lime is released into flue
gas temperatures in this whole temperature range (1700-3000.degree.
F.). Ideally, most of the unreacted lime is released between
1700.degree. F. and 2600.degree. F. This calcitic lime release from
the oxidized coke char (analogous to flue gas injection) can be
effective in control of unreacted SOx, either from the pet coke or
other sources (e.g. blended coal). This release of unreacted lime
can be controlled to some degree by the fuel properties and the
combustion characteristics of the modified coke of the current
invention. That is, the modified pet coke char would primarily
complete burnout in a temperature zone that minimizes sintering,
but provides access to adsorption of SOx sufficiently prior to the
ideal temperature window for optimal reactions. In turn, char
burnout and availability of the calcitic lime can be controlled, to
a certain degree, by the coke particle size distribution, VCM
quality, and VCM content of the modified pet coke. In this manner,
the performance of the calcitic lime as the desired sulfur reagent
is significantly improved. Its performance can be further optimized
(to a certain extent) in the combustion of the modified pet coke
via process options of the current invention.
[0931] Any unburned pet coke char can be used for adsorption of
mercury and other air toxics in the flue gas downstream of the
furnace. If pet coke char remains unoxidized, some sulfur ions in
the internal pores are likely to be unoxidized, as well. These
sulfur ions can react with mercury, which is adsorbed on the pet
coke surface, to form mercury sulfide (HgS). Sulfur impregnated
activated carbons, used for mercury removal, have similar types of
chemisorption reaction mechanisms. In addition, remaining pet coke
char can also have sufficient porosity and surface area to adsorb
dioxins and other air toxics in the flue gas from the pet coke or
other sources.
[0932] (4) Other Embodiments
[0933] a. Supersaturated Solutions of Calcitic Hydrate:
[0934] Another embodiment of the current invention is the use of a
supersaturated solution of calcitic hydrate for coke quench water.
This embodiment is desirable in cases where a saturated solution of
calcitic hydrate is not sufficient to achieve the Ca/S ratios
required for higher coke sulfur levels and/or higher sulfur removal
requirements of a particular application.
[0935] Various means can be used to achieve a supersaturated quench
solution of calcitic hydrate in water. The simplest means would
include the use of chilled water to increase solubility of the
calcitic hydrate (Ca(OH).sub.2) in water. Unlike most solutes,
calcitic hydrate or calcium hydroxide has decreasing solubility
characteristics as temperature increases. Thus, chilling the quench
water increases the solubility and, hence, the quantity of calcitic
hydrate totally dissolved in solution. As the temperature
increases, the calcitic hydrate would remain in solution as long as
there are no suspended particles that nucleate and precipitate the
calcitic hydrate out of solution. Also, suspended calcitic hydrate
cannot be available to remain in equilibrium with the solution.
This supersaturated solution could then be used as coke quench in
the coker quench cycle. As such, incremental amounts of calcitic
hydrate would be deposited in the internal crystalline structure of
the modified pet coke. The lower temperature limit (or upper
solubility limit) for this approach is less than the freezing point
of the pure solvent (i.e. water@32.degree. F.) due to the freezing
point depression of the solvent in solution.
[0936] Unfortunately, this supersaturated solution can be difficult
to achieve on a consistent basis in a coker process environment.
Impurities in the recycled coke quench water (e.g. other calcium
compounds or suspended coke fines) can serve as nucleation to
precipitate excess calcitic hydrate out of solution before reaching
the coke drums as coke quench. In addition, the preparation of the
supersaturated solution may not be practical, in many cases, due to
other technical and economic considerations. Furthermore, the
increase in solubility of the supersaturated solution may still not
be sufficient to provide the desired calcitic hydrate, totally
dissolved in the coke quench solution.
[0937] b. Saturated Solution of Calcitic Hydrate with Suspended
Calcitic Hydrate Solids:
[0938] An alternative embodiment to the saturated or supersaturated
solution (calcitic hydrate in water) would be the use of a
saturated solution with suspended solids of calcitic hydrate.
Again, this embodiment is desirable in cases where a saturated or
supersaturated solution of calcitic hydrate is not sufficient to
achieve the Ca/S ratios required for higher coke sulfur levels
and/or sulfur removal requirements of a particular application. In
this embodiment, the calcitic hydrate would be preferably produced
without the traditional agglomeration step and/or pulverized to the
smallest practical particle size distribution: <4 microns and
preferably 100%<1 micron. In many cases, most of the calcitic
hydrate will still be deposited out of the saturated solution onto
the internal surfaces of the modified coke's micropores and
mesopores. The residual lime from solution and the suspended lime
solids will be deposited on the macropores. That is, much of the
suspended calcitic hydrate solids (1-4 micrometers) will not be
small enough to be integrated into the micropores (diameter <2
nanometers) and mesopores (d=2-50 nanometers), but deposited in the
macropores (d>50 nanometers). As noted earlier, cutting the coke
from the drums and pulverization to a fineness of 70-95% <200
mesh (d=.about.74 micrometers) can cause significant portions of
the calcitic hydrate deposited on the macropore walls to become
part of the external surface of the coke particles. This
potentially exposes these reagents to weathering during transport
and high-temperature flame zones in the combustion process,
respectively. The calcitic hydrate suspended solids deposited in
the coke macropores are more likely to suffer detrimental sintering
effects (vs. dissolved calcitic hydrate deposited from solution).
This is primarily due to their larger particle size (vs. molecular
layers <2 nanometers). In contrast, the rest of the calcitic
hydrates deposited on the macropore walls will still be part of the
internal surface of the coke particles after pulverization. The
proportion of each will depend on the coke crystalline structure
and the type/degree of coke cutting and pulverization. In any case,
the Ca/S ratio will likely need to be increased to compensate for
losses to weathering and sintering of some suspended solids of
calcitic hydrate. In many cases, this will partially offset the
improvements in reagent utilization for the desired SOx removal
efficiency. One skilled in the art can readily make adjustments in
Ca/S ratios to achieve the desired SOx removal efficiency for a
particular application of this technology.
[0939] c. Various Solutions of Dolomitic Hydrates as Coke
Quench:
[0940] As noted above, dolomitic limes can be preferable sulfur
reagents (e.g. sorbents) to calcitic limes in some cases. In
certain applications, the impregnation with dolomitic hydrates
(Ca(OH).sub.2 with MgO or Mg(OH).sub.2) is preferable to calcitic
hydrate due to (1) greater resistance to sintering, and/or (2)
higher sulfur reactivity. Either or both of these reasons can lead
to higher sulfur removal capabilities. In these cases, proper
consideration should be given to additional costs, higher ash
loading in boiler/particulate control device(s), and magnesium
impacts on ash fouling/reuse characteristics. In many applications,
however, the higher SOx removal efficiencies can be more critical
than these concerns. The impregnation of the modified pet coke with
dolomitic hydrates may normally be similar to the exemplary
embodiment (described above). Various solutions of dolomitic
hydrates can be used as coke quench in the delayed coker quench
cycle: saturated, sub-saturated, and saturated with suspended
dolomitic hydrate solids.
[0941] The dolomitic hydrates have two primary forms: monohydrate
and dihydrate. Both forms are made form dolomitic quicklime, which
is derived from limestone containing 35 to 46 percent magnesium
carbonate. The monohydrate (or atmospheric hydrated dolomite) has
the hydrate of quick lime (CaO) with magnesium oxide:
Ca(OH).sub.2*MgO. The monohydrate typically has the following
chemical composition: 46-48 wt. % calcium oxide, 33-34 wt. %
magnesium oxide and 15-17 wt. % chemically combined water. The
dihydrate (or pressure hydrated dolomite) has the hydrated oxides
of both calcium and magnesium: Ca(OH).sub.2*Mg(OH).sub.2. The
dihydrate typically has the following composition: 40-42 wt. %
calcium oxide, 29-30 wt. % magnesium oxide and 25-27 wt. %
chemically combined water. The dihydrated form of dolomitic lime
(i.e.Ca(OH).sub.2*Mg(OH).sub- .2) is normally preferable over the
monohydrate form due to generally higher specific surface area and
smaller particle size distribution in conventional production. Both
of these factors provide incremental SOx removal.
[0942] This embodiment using dolomitic hydrates can best be
summarized by again reviewing (1) selection of dolomitic hydrates
as desired sulfur reagent, (2) preparation of the coke quench
solutions, (3) modification of quench cycle in the coking
operation, (4) pulverization of pet coke fuel, and (5) performance
of the reagent in the combustion of the modified pet coke.
[0943] c1. Selection of Dolomitic Hydrates as Sulfur Reagent:
[0944] The primary differences between dolomitic hydrates and
calcitic hydrates are resistance to sintering, reactivity, and
solubility characteristics. First, sintering studies with furnace
injection of the prior art have shown that calcitic hydrates can
lose up to 50% of its BET surface area in furnace temperatures
>2000.degree. F. In contrast, dolomitic hydrates can increase up
to 50% in surface area in similar prior art conditions. As such,
dolomitic hydrates apparently have a much greater resistance to
sintering. Secondly, the sulfur reactivity of the dolomitic
hydrates is enhanced by the presence of the magnesium. Though it
improves calcium utilization, magnesium is essentially chemically
inert in the prior art furnace injection. Also, the unreacted
magnesium can detrimentally impact ash fouling characteristics,
total ash loading, and ash reuse/disposal. In the prior art,
studies have shown that SOx removal on a mass basis (i.e. Lbs.
SOx/Lbs. Sorbent) is similar for calcitic hydrate and dolomitic
hydrates. However, prior art studies have also shown that dolomitic
hydrates are capable of up to 75% SOx removal vs. up to 60% for
calcitic hydrate. In addition, the dolomitic hydrates in the
current invention will have additional reaction mechanisms to react
with non-oxide forms of sulfur (discussed below). Finally, the
solubility of dolomitic hydrates is slightly higher due to the
weaker bonds of a less symmetrical crystalline structure (i.e.
dolomitic hydrates as a solute). Unfortunately, the degree of
unreacted magnesium can offset the ability to totally dissolve a
greater mass of dolomitic hydrates.
[0945] c2. Preparation of Coke Quench Solutions With Dolomitic
Hydrates:
[0946] Overall, dolomitic hydrates have very similar physical and
chemical properties as calcitic hydrate. As such, the above
discussions regarding calcitic hydrate and its associated quench
solutions generally apply to dolomitic hydrates, as well. The
various coke quench solutions of dolomitic hydrates are discussed
below, primarily noting any significant differences:
[0947] 1. Saturated and Sub-Saturated Solutions of Either Dolomitic
Hydrate: The solubility of dolomitic hydrates are generally higher
than calcitic hydrate due to their weaker crystalline structures
with the presence of both magnesium and calcium (i.e. vs. pure
Ca(OH).sub.2 or pure Mg(OH).sub.2). This typically allows coke
impregnation of greater mass for the dolomitic hydrates. In many
cases, the increased reactivity of the magnesium in the current
invention makes the higher solubility advantageous. In contrast,
the unreactive nature of the magnesium with furnace injection of
the prior art often negates this advantage. In addition, the
decrease in water solubility associated with increasing temperature
can be substantially lower in dolomitic hydrates (discussed in item
2.). Thus, less mass of dolomitic hydrates can be impregnated in
the coke without evaporation of coke quench, in many cases.
[0948] 2. Supersaturated Solution of Either Dolomitic Hydrate:
Supersaturated solutions of dolomitic hydrates are more difficult
to achieve than supersaturated solutions of calcitic hydrate. As
discussed previously, calcium oxide (CaO) and calcium hydroxide
(Ca(OH).sub.2) have an unusual solubility characteristic: lower
water solubility with increasing temperature. In contrast,
magnesium oxide (MgO) and magnesium hydroxide (Mg(OH).sub.2)
increase in water solubility with increasing temperature. Though
some dolomitic hydrates contain equal moles of calcium and
magnesium compounds, the degree of solubility increase for chilled
water will be significantly less, and partially depend on the type
and origin of the dolomitic hydrates. Thus, other means of creating
a supersaturated solution would be required in many cases.
[0949] 3. Saturated Dolomitic Hydrate Solution with Suspended
Dolomitic Hydrate Solids: This approach is very similar to a
saturated solution containing suspended calcitic hydrate solids.
Conventional production of the dihydrate form has particle size of
roughly 1.0-4.0 micrometers, which is similar to calcitic hydrate.
However, conventional production of the monohydrate form typically
has particle size of 14-20 micrometers. With either dolomitic
hydrate, the size of the suspended particles should be as small as
practical (preferably <1.0 micron) for the particular
application.
[0950] c3. Modification of Coke Quench Cycle in the Coking
Operation:
[0951] The coke quench cycle is very similar to the description for
calcitic hydrate. The primary difference is modifications to
compensate for differences in solubility characteristics: water
solubility at ambient temperatures and related temperature effects.
One skilled in the art can make modifications in equipment and
operations to address these concerns in particular applications of
the current invention.
[0952] c4. Impacts of Pet Coke Fuel Pulverization:
[0953] The pulverization impacts for pet coke with dolomitic
hydrates are very similar to the pulverization description for the
exemplary embodiment. The primary difference is dolomitic hydrates
have greater resistance to sintering. Thus, the dolomitic hydrates
left on the external surface of the fuel coke particles due to
pulverization will maintain higher sulfur removal capabilities.
Again, the dolomitic hydrates, that are deposited from dissolved
solution (not suspended solids), have molecular layers that are
less prone to sintering, even on the external surface of the
pulverized coke particles. Though the coke char of the current
invention offers protection from sintering, this resistance to
sintering can be advantageous, particularly on the external surface
of the pulverized coke particles. One skilled in the art can make
modifications in equipment and operations to optimize these
concerns in particular applications of the current invention.
[0954] c5. Performance of Dolomitic Hydrates in the Combustion of
the Modified Pet Coke:
[0955] The most important difference in the use of dolomitic
hydrates versus calcitic hydrate is its potential for higher sulfur
removal capabilities. The improved performance of dolomitic
hydrates in the current invention is due to two primary factors:
(1) magnesium and pet coke's roles in reducing detrimental
sintering effects and (2) enhanced sulfur reactivity of
magnesium.
[0956] Reduced sintering effects in the current invention can
improve the sulfur removal performance of the dolomitic hydrates
over their use in the prior art. As discussed earlier, the
magnesium of the dolomitic hydrates substantially increases the
calcium utilization in the prior art, primarily due to the much
greater resistance to sintering. That is, furnace injection of the
dolomitic hydrates has shown an increase in surface area up to 50%
(vs. up to 50% reduction in BET surface area for calcitic hydrate).
In the current invention, this phenomenon is expected to increase
the surface area. Hence, SOx removal is higher for any dolomitic
hydrates deposited from suspended solids. This can be particularly
true for dolomitic hydrates on pores that become part of the
external surface of the coke particles after pulverization. In
addition, the molecular deposition from dissolved dolomitic
hydrates is expected to also reduce impacts of sintering, as noted
before. That is, the insulation properties of the modified pet coke
offer sintering protection for dolomitic hydrates deposited in the
internal pores. Consequently, the overall impact of the current
invention is to further reduce the detrimental effects of sintering
and further enhance the calcium utilization, in most cases.
[0957] The sulfur reactivity of magnesium can be substantially
enhanced by the current invention in two ways: (1) improvement of
magnesium reactivity with sulfur oxides and (2)promotion of
magnesium reactivity with non-oxide forms of sulfur. First, the
reaction of magnesium with sulfur oxides (SOx) in the prior art is
apparently very limited due to the unstable nature of magnesium
sulfate at the furnace injection temperatures (e.g. MgSO.sub.4
decomposes at temperatures >2050.degree. F.). The modified
petroleum coke of the current invention can effectively insulate,
to a certain extent, this desirable reaction from high temperature
zones (i.e. >2000.degree. F.). As the coke char increases in
temperature to roughly >660.degree. F., any magnesium hydroxide
(i.e. hydrated magnesium oxide Mg(OH).sub.2) in the dolomitic
dihydrate losses water; dehydrating to form magnesium oxide (MgO)
crystals. As the coke char reaches temperatures >1000.degree. F,
the heavy organic compounds (i.e. aromatics, asphaltenes, &
resins) in the polymeric coke structure start to thermally crack or
break apart at a molecular level. These cracking reactions release
carbonium ions and sulfur (or sulfur complex) ions in the vapor
state. If oxygen is available at the coke surface, the sulfur ions
readily oxidize to form sulfur oxides. The gaseous sulfur oxides
can then migrate along the coke surface until converted by the
calcium oxide and/or magnesium oxide. The modified pet coke can
shield these reactants in its internal pores for sufficient time to
form MgSO.sub.4 and prevent exposure to temperatures above
2000.degree. F. Unfortunately, high concentrations of oxygen are
not generally available in the coke's inner pores at lower
temperatures. Secondly, a high degree of unoxidized coke char
downstream of 2000.degree. F. flue gas temperatures is not
desirable, in most cases, due to low combustion efficiency and
other considerations. Therefore, magnesium reactivity with sulfur
oxides is often improved (vs. prior art) by this reaction mechanism
of the current invention, but only to a limited extent.
[0958] An alternative reaction mechanism of the current invention
promotes magnesium reactivity with non-oxide forms of sulfur.
Again, the heavy organic compounds (i.e. aromatics, asphaltenes,
& resins) in the polymeric coke structure start to thermally
crack at temperatures over 1000.degree. F, and release carbonium
ions and sulfur (or sulfur complex) ions in the vapor state. These
very reactive carbonium and sulfur ions typically oxidize when
oxygen is present. However, the internal pores and even some of the
external surface of the coke char are not readily exposed to oxygen
at the early stages of the char oxidation. These gaseous ions can
migrate within the coke pore structure to the reaction sites of
magnesium oxide. In the proper conditions at these high
temperatures, the very reactive carbonium and sulfur ions can
exchange ionic bonds oxidizing the carbonium ion and forming
magnesium sulfide (MgS). Unlike calcium sulfide (CaS), magnesium
sulfide is thermochemically stable at these temperatures and higher
(i.e. decomposes at T>3632.degree. F.). It is also a collectible
particulate at these and lower temperatures. Chemisorption occurs,
if the impregnated magnesium oxide reacts with the sulfur compounds
adsorbed on the carbon surface (i.e. reaction mechanism 2. in the
general discussion of the current invention). This reaction
mechanism is analogous to gaseous mercury (Hg) reacting with solid
sulfur crystals impregnated on activated carbon at much lower
temperatures. In this manner, part of the magnesium, which is
essentially chemically inert in the prior art, becomes reactive in
the current invention. The degree of sulfur reactivity depends on
various factors, including the (1) local temperature, (2) types,
reactivity, and diffusion of the carbonium & sulfur ions, and
(3) length of time carbon char internal pores or surface remains
without oxygen. These factors are influenced by the pet coke's
composition, crystalline structure, and degree of pulverization.
The design and operation of the furnace in the pet coke user's
system also influence them. This reaction mechanism is not the only
means by which magnesium's sulfur reactivity is increased in the
current invention. As such, the present invention should not be
limited by this theory of operability.
[0959] Another major benefit of using dolomitic hydrates is a
substantial reduction of the detrimental effects of heavy metals
(e.g. V & Ni) in the petroleum coke. The dolomitic hydrates
mitigate superheater fouling, high temperature ash corrosion, and
low temperature sulfuric acid corrosion. Dolomite is currently used
as a combustion additive in heavy fuel oil firing to alleviate
these problems. The reduction of fouling and high temperature
corrosion is basically achieved by producing high melting point ash
deposits, that can easily be removed by sootblowers or lances. Low
temperature sulfuric acid corrosion is reduced by the formation of
refractory sulfates by reaction with the sulfur trioxide (S0.sub.3)
gas in the flue gas stream. By removing the sulfur trioxide, the
dew point of the flue gas is sufficiently reduced to protect the
metal surfaces. Similar to the dolomitic hydrates, the dolomitic
carbonates (i.e. dolomite) calcine into the oxides of magnesium and
calcium, after heating in the primary flame zone (i.e. losing
carbon dioxide vs. water). The sulfating ability of these oxides
produces dry, collectible ash compounds (e.g. CaSO.sub.4 &
MgSO.sub.4), and limit undesirable compounds of vanadium, nickel,
and sulfur (e.g. vanadium pentoxide, sulfates of Ni, Na, & K;
& various vanadates). In prior art practices, the magnesium
oxides, as well as the calcium oxides, react with sulfur oxides to
form sulfates. This occurs despite being injected with the fuel oil
and exposed to the primary flame without protection from sintering
effects. The amount of fuel additive is generally equal to the ash
content of the fuel or 2-3 times the vanadium content. The lafter
is normally prescribed in situations, where high temperature
corrosion is the primary concern. However, the amount of dolomitic
hydrates impregnated on the petroleum coke in the current invention
is normally in substantial excess of either amount. Therefore, the
impregnated dolomitic hydrates should readily mitigate the
detrimental effects of the heavy metals in the petroleum coke.
[0960] In conclusion, dolomitic hydrates can be the desired sulfur
reagent in many applications of the current invention. The primary
benefits of dolomitic hydrates include (1)increased sulfur
reactivity, (2) increased solubility in water, (3) less sintering
effects, and (4)proven ability to mitigate ash problems with heavy
metals in fuel. These benefits are particularly advantageous in
cases where magnesium is significantly more reactive than dolomitic
sorbent injection of the prior art. The primary detriments of
dolomitic hydrates include additional costs and potential negative
effects of magnesium on ash quality and quantity. These factors
need to be properly evaluated for each application of the current
invention. One skilled in the art can make such evaluations and
determine the most desired sulfur reagent. Appropriate process
options of the current invention can be employed, based on
performance requirements, engineering calculations, and tests, if
necessary.
[0961] d. Mixture of Calcitic Hydrate and Dolomitic Hydrates:
[0962] The sulfur reagent impregnated on the modified pet coke of
the current invention can be optimized by various mixtures of
calcitic hydrate and dolomitic hydrates. This alternative
embodiment potentially offers the opportunity to optimize the
physical & chemical properties and achieve the optimal sulfur
reagent. In this manner the potential benefits can be maximized
and/or the risks/detriments minimized. The preparation and use of
such mixture would be very similar to the above discussions for the
exemplary embodiment and the alternative embodiment for dolomitic
hydrates.
[0963] e. Other Types of Reagents:
[0964] Other types of sulfur reagents can be impregnated on the
internal surface of the modified pet coke using the same
methodology of the current invention. These sulfur reagents can
react with various forms of sulfur (i.e. with and/or without sulfur
oxides). Other sulfur reagents would include, but should not be
limited to the following:
[0965] 1. Other Alkaline Earth Metal Reagents: Limestone, dolomite,
limes, magnesia, etc.
[0966] 2. Alkali Metal Reagents: Potassium hydroxide, sodium
hydroxide, potassium iodide, etc.
[0967] 3. Other Sulfur Reagents: Transition element compounds,
Nonmetal compounds, etc.
[0968] As noted previously, alkali metal reagents, particularly
sodium reagents, have a tendency to form undesirable compounds
(e.g. various sodium vanadates) before reaching the desired
temperature window in the combustion system to react with sulfur
oxides. However, the increased solubility may be very advantageous
in cases where pet coke heavy metals are not a major problem. Also,
sulfur reagents with certain solubility characteristics (e.g. like
calcium hydroxide) can be used in quench water even without the
evaporation of the water.
[0969] For each type of sulfur reagent, the stoichiometric ratios
and reaction temperature windows in the combustion environment
would need to be determined for the desired or optimal sulfur
removal efficiencies. One skilled in the art can use this
information to modify the methodology of the current invention to
achieve the desired impregnation of the petroleum coke.
[0970] f. Combination of Sulfur Reagents:
[0971] A combination of any of the above sulfur reagents, including
calcitic and dolomitic hydrates, can be used to optimize physical
and chemical properties for coke impregnation and sulfur
conversion. For example, a combination of sulfur reagents could be
used to overcome solubility limits that prevent the impregnation of
sufficient amounts of a sulfur reagent in a reasonable quantity of
quench water. For example, the combination of calcium hydroxides
and potassium hydroxides could provide several advantages.
[0972] g. Combination of Impregnated Sulfur Reagent with Other
Types of Sulfur Removal:
[0973] In some applications of the current invention, the
combination of impregnated sulfur reagent on the pet coke and other
sulfur removal technologies may be desirable to optimize/maximize
sulfur removal. That is, the combined sulfur removal technologies
can provide additional or more optimal sulfur removal. Furthermore,
other sorbent injection systems can enhance SOx removal
sufficiently in cases where sufficient SOx removal is not possible
due to high coke sulfur levels and/or ash loading limitations (i.e.
beyond reach of soluble sorbents and sintered suspended solids).
For example, calcitic hydrate in economizer at flue gas
temperatures near 840 to 1020.degree. F. can effectively supplement
the sulfur removal from pet coke impregnated with sulfur
reagent(s). In some cases, lime is already used on-site for other
purposes (e.g. water treatment). Incremental costs of additional
lime capacity and injection grid can be minimal due to reduced size
of the required system. This solution, however, may limit boiler
load fluctuations due to temperature sensitivity of injection zone
for various boiler loads. Also, minimum impregnation of pet coke
with dolomitic hydrates may be desirable to mitigate ash and
corrosion problems associated with heavy metals in fuel. In this
manner, a separate sorbent injection system can provide any
additional SOx removal required.
[0974] h. Additives to Enhance Solubility Characteristics and/or
Resistance to Sintering:
[0975] Certain additives can be used to enhance solubility
characteristics and/or resistance to sintering. Both these
characteristics of the sulfur reagent(s) depend on the strength of
the crystalline structure. For solubility, a weaker crystalline
structure causes higher solubility in water. For resistance to
sintering, a stronger crystalline structure at higher temperatures
prevents sintering, which is essentially the partial collapse of
the crystalline structure. Ideally, the crystalline structure of
the sulfur reagent in the current invention is stronger as the
temperature increases. That is, weaker crystals in cold water allow
high solubility in coke quench water. At higher temperatures, the
stronger crystalline structure decreases water solubility, which
allows deposition of sulfur reagent even without quench water
evaporation. The stronger crystalline structure at high
temperatures also improves resistance to sintering significantly.
Unlike most salts, calcitic hydrates have this physical property:
lower water solubility at higher temperatures and some resistance
to sintering. The magnesium in dolomitic hydrate apparently
strengthens the crystalline structure(s) at higher temperatures. As
a result, the water solubility at ambient temperatures is
increased, the water solubility >200.degree. F. is slightly
lower, and the resistance to sintering is substantially improved.
It should be noted that the dolomitic hydrate has a greater
capacity for deposition from quench water that is either evaporated
or not evaporated. In a similar manner, other additives can be used
to enhance the solubility characteristics and resistance to
sintering in other sulfur reagents of the current invention.
[0976] i. Soaking or Spraying Impregnation of Sulfur Reagent on the
Pet Coke:
[0977] Methods of impregnation similar to activated carbon
impregnation can also be used for the modified pet coke of the
current invention. The basic methods soaking and/or spraying
methods can be used to impregnate sulfur reagent on the modified
pet coke. Unfortunately, the impregnation will likely predominate
near the exterior surface, due to lack of penetration into the
internal pores. Consequently, the sintering protection offered by
the pet coke char would be limited in many cases.
[0978] j. Impregnated Pet Coke in Staged Fuel Burners:
[0979] The modified pet coke impregnated with sulfur reagent can be
effectively used in staged burners that moderate temperature
profiles and make sintering less detrimental. As discussed
previously, low NOx combustion technologies tend to create less
intense combustion that lengthens the primary flame zones and
moderates flame temperatures. This tends to reduce sintering of the
sulfur reagent. In addition, some low NOx combustion techniques
employ staged fuel combustion to "reburn" the primary flame
combustion products in a reducing atmosphere that reduces NOx. If
solid fuels are used in the second stage (current burners to those
yet to be designed), a modified pet coke of the current invention
can be optimized for this service. Since the secondary fuel is not
exposed to the high temperatures of the primary flame zone, the
impregnated sulfur reagent would experience less sintering and
require less sintering protection from the pet coke char.
Consequently, the modified pet coke can be optimized via process
options of the current invention to provide the reducing atmosphere
to decrease NOx, complete combustion in the firebox, and still
offer desired SOx removal. Examples: US DOE/B&W's Limestone
Injection Multistage Burner (LIMB) or Reburn burners for Low NOx
combustion, particularly in cyclone boilers.
[0980] k. Impregnated Pet Coke with High-Calcium Coals:
[0981] Some coals (e.g. subbituminous) have high calcium
concentrations due to inherent limestone deposits within the coal
seams. If the modified pet coke of the current invention is blended
with such coals, the calcium in these coals can react with the
sulfur oxides to form collectible sulfates. However, as noted
earlier, exposure of this calcium (e.g. CaO) to the primary flame
can substantially reduce its effectiveness as a sulfur reagent due
to sintering effects. If the calcium present in the coals is due to
dolomite deposits within the coal seams, the sintering effects are
probably reduced substantially. In either case, the calcium in the
fuel blended with the pet coke can reduce the sulfur oxides to some
degree. Thus, modifications to the impregnation (e.g. reduction in
Ca/S stoichiometric ratio) and combustion characteristics (e.g. VCM
quantity & quality) of the modified pet coke should reflect
this effect on SOx removal. Depending on the blending proportions,
this could eliminate the need for impregnation of sulfur reagent
altogether in some cases.
[0982] B. Adsorption & Other Impregnation of Pet Coke
Pores:
[0983] Enhanced Fuel Qualities
[0984] The ability to use the carbon adsorption character of the
modified coke to improve fuel properties was briefly described
earlier in the current invention. Various hydrocarbons and other
non-polar compounds are added to the modified coke via adsorption.
Similar to the sulfur reagents, other chemical agents are added via
impregnation. Both adsorption and impregnation are accomplished via
the coke quench of the decoking cycle. The adsorption and
impregnation of desirable compounds are discussed below in further
detail.
[0985] (1) Addition of Volatile Combustible Materials (VCMs):
[0986] As described previously, the addition of volatile
combustible materials (VCMs) to the modified pet coke can be
advantageous in many applications of the current invention. Both
the quality and quantity of VCMs are key factors in improving fuel
character and performance.
[0987] The volatile matter or volatile content of a fuel is
determined by ASTM Method D 3175. In this test method, all
vaporized compounds when a fuel reaches 950+/-20.degree. C.
(1742+/-68.degree. F.) for seven minutes are considered volatile
content. These compounds normally include moisture, carbon
monoxide, and various hydrocarbons. As such, the volatile content
is composed of organic and inorganic compounds. On the other hand,
Volatile Combustible Materials (VCMs) refers to these compounds
that can be oxidized further in a combustion environment. Though
VCMs can be inorganic (e.g. carbon monoxide), most VCMs are
organic, hydrocarbon compounds with various degrees of hydrogen
saturation.
[0988] For the current invention, Volatile Combustible Materials
(VCMs) are classified by boiling points: high-quality:
<750.degree. F, medium quality: 750 to 950.degree. F, and
low-quality: >950.degree. F. The high quality VCMs primarily
help with initiating and sustaining combustion. The low quality
VCMs primarily help with char burnout. The medium quality VCMs can
help with either depending on the point of release in the
combustion process and the degree of difficulty in oxidation.
Consequently, VCM performance in the modified coke of the current
invention depends on types of VCM compounds, costs, and physical
& chemical properties. Cost vs. performance trade-offs need to
be evaluated for each application. Ideally, waste streams of
acceptable quality (e.g. used lubricating oils and certain
hazardous wastes) are readily available.
[0989] The integration of VCMs on the pet coke in the current
invention occurs in two key stages. First, VCMs (mostly
low-quality) increase due to the coker process modifications that
assure sponge coke and increase porosity. The quantity of this
increased VCM depends on the severity of the process changes
(described earlier). The VCM quality depends on the types of VCM
compounds that become part of the modified pet coke crystalline
structure. Secondly, VCMs can be added to the modified pet coke via
the coke quench. The addition of VCMs normally involves (but not
always) the improved carbon adsorption characteristics of the
modified coke. Most, if not all, of the VCMs integrated on the
modified pet coke are organic hydrocarbons that are fairly
insoluble in water. After the pet coke has cooled sufficiently to
prevent vaporization of the VCMs, the chosen VCMs can be injected
into the coke quench water. The improved carbon adsorption
properties of the modified coke cause effective adsorption of most
VCMs on the internal surface area of the pet coke pores. As
discussed earlier, the relative sizes of the VCM molecules and the
modified coke's pores will determine adsorption effectiveness. In
this manner, the quantity and quality of the VCMs can be
controlled. Desirable VCMs that are somewhat soluble in water (e.g.
alcohols, phenols) can still be integrated into the modified pet
coke via a combination of carbon adsorption and solubility
characteristics. For example, a fairly non-polar alcohol can be
adsorbed, particularly if the quantity of alcohol is greater than
saturation. However, polar VCMs that are very soluble in water can
be more difficult to adsorb. If these VCMs have high boiling
points, impregnation similar to sulfur reagents may be possible.
Consequently, evaluation of the adsorption of low-cost VCMs can be
required. One skilled in the art can readily evaluate availability,
costs, and the properties of VCMs to determine the optimal VCMs to
integrate on the pet coke for specific applications of the current
invention.
[0990] (2) Addition of Ionizing Compounds:
[0991] The addition of ionizing compounds to the modified petroleum
coke can be advantageous in certain combustion applications.
Ionizing compounds can be selected from various chemical agents
that increases the quantity and/or quality of ions in the
high-temperature, combustion products (e.g. plasma). Alkali metals
typically have the lowest ionization energies. Alkaline earth
metals are the family of elements of next lowest ionization
energies. As such, ionic compounds (e.g. oxides, hydroxides,
carbonates, etc.) of alkali metals and akaline earth metals have
many desirable characteristics of ionizing agents. Many of these
ionizing compounds are the same compounds that are desirable for
SOx sorbents. Likewise, the addition of these ionizing agents to
fuel-grade petroleum coke has similar concerns to the addition of
sulfur sorbents. That is, their undesirable ash compounds and
solubility issues make the alkali metal compounds less desirable
than the alkaline earth compounds in many cases. Consequently, the
addition of calcitic hydrate is an exemplary embodiment for the
addition of ionizing compounds, as well. The preference for this
ionizing agent can be dependent on the combustion application and
other pet coke properties. In addition, other embodiments for the
addition of ionizing agents would include, but should not be
limited to (1) other calcitic, dolomitic, potassium, and/or sodium
compounds, (2) addition via coke quench solution (saturated,
sub-saturated, supersaturated, and saturated with suspended
solids), and/or (3) in combination with other chemical additives
that enhance ionization.
[0992] As discussed previously, Magnetohydrodynamic (MHD) electric
generation is a prime example of advantageous addition of ionizing
agents to modified pet coke. MHD occurs when hot, partially ionized
combustion gases (plasma) are expanded through a magnetic field.
The hot gas can be produced in a ceramic coal combustor with
temperatures approaching 5000.degree. F. Even at these high gas
temperatures, the available gas ionization normally needs to be
increased significantly. Thus, MHD technology often requires the
seeding of the hot plasma gas with ionizing compounds. Various
types of ionizing compounds can be used, including calcitic
hydrate. However, potassium hydroxide can be preferable due to ease
of ionization, if potassium hydroxide solubility and resulting ash
compounds are not prohibitive. In these cases, one skilled in the
art can determine the proper quantity of potassium hydroxide
desired and make adjustments to the type of coke quench solution
(e.g. saturated).
[0993] Coal has been traditionally used as the preferred fuel in
the research for MHD technology. The modified pet coke of the
current invention offers many advantages over various coals for MHD
technology. First, the modified pet coke has >90% less ash,
>25-60% greater heating value, and substantially lower moisture
content. These characteristics potentially provide higher flame
temperatures, lower air/oxygen temperature requirements, and/or
less ash problems in combustor and downstream heat exchange.
Secondly, the pet coke can be readily pulverized to a finer
particle size distribution to assure compact, intense, and
efficient flame generation. Finally, VCMs, ionizing agents, and/or
other desirable compounds (e.g. oxygen-containing) can be uniformly
added to the modified coke of the current invention. That is, coke
quench would provide the means to add ionizing agents in a manner
similar to sulfur reagents. The quality and quantity of these
potentially desirable compounds can be optimized, as well.
[0994] An exemplary embodiment of the current invention for MHD
technology may include modified pet coke production from a sweet
crude coker. Thus, the modified pet coke would have low-sulfur and
low-metals contents to prevent downstream ash problems. Also, the
modified pet coke would have a high porosity, crystalline structure
that would allow very fine pulverization (>90% through 200
mesh). The quantity and quality of VCMs (via modified coker process
conditions and/or coke quench addition) can be optimized to
initiate and sustain combustion. The fine pulverization and optimal
VCMs provide efficient combustion with a stable, compact flame. In
addition, oxygen-containing compounds can be added to reduce the
required air/oxygen stream, if desirable. Finally, potassium
hydroxide or potassium iodide can be readily added as the ionizing
agent via coke quench. That is, the solubility of either potassium
compound is sufficient to uniformly deposit molecular layers via a
saturated quench solution during the entire quench cycle. That is,
the evaporated quench solution will leave the molecular layers on
the internal pores of the modified pet coke. The non-evaporated
quench would still be saturated to prevent uptake of the deposited
potassium compound into an unsaturated quench solution. One skilled
in the art can determine the proper quantity desired for the MHD
application, and impregnate them on the pet coke via coke quench.
The use of saturated, sub-saturated, super-saturated, or saturated
with suspended solids is again similar to the exemplary embodiment
for the addition of SOx sorbents.
[0995] (3) Addition of Oxygen-Containing Compounds:
[0996] Various types of oxygen compounds can be added to the
modified pet coke to reduce excess air required and/or reduce
impact of oxygen diffusion as a kinetic reaction limitation for
various reactions (e.g. sulfur reagents). For either purpose, the
oxygen compound, in general, will make the oxygen readily available
to react with other species at higher temperatures. In other words,
the oxygen compound will generally be an oxidizing agent. The type
of oxygen compound can determine its role. For example, oxygen
compounds that have boiling points <750.degree. F. will likely
volatilize in the primary flame zone. This can reduce excess air
requirements for the primary flame zone and improve low NOx
combustion. Secondly, an oxygen compound that has a boiling point
>950.degree. F. (e.g. large, phenolic compounds) can help char
oxidation and reduce overall excess air requirements for complete
combustion. Also, this type of oxygen compound can provide oxygen
in the internal pores to promote earlier oxidation of sulfur. In
turn, this can help promote desired SOx reaction mechanisms
reaction with sulfur reagent(s).
[0997] As with VCMs, the addition of oxygen compounds can be
accomplished with wither coke adsorption or impregnation via
solubility characteristics. In either case, the oxygen compounds
are integrated via the coke quench solution. Selection of the
optimal oxygen compound depends on desired performance,
availability, costs, and physical/chemical properties. One skilled
in the art can determine optimal oxygen compound(s) to integrate on
the pet coke for specific applications of the current
invention.
[0998] (4) Optimization of Coke Fuel Catalyst Properties:
[0999] The ability to optimize the oxidation catalytic activity in
the modified pet coke has been previously discussed. Combustion of
the modified pet coke of the current invention can overcome
problems of the traditional pet coke, while promoting better
combustion via oxidation catalysts.
[1000] The `heavy` transition metals (e.g. V, Ni, Fe, & Cu) in
the fuel-grade coke of many refineries have been traditionally
viewed as undesirable components. First, these transition metals,
good oxidation catalysts, promote the oxidation of sulfur dioxide
to sulfur trioxide. Without dry scrubbing, higher sulfur trioxide
concentrations cause significantly higher flue gas dew points. The
higher dew points cause lower combustion efficiency due to higher
stack temperatures and/or cold-end corrosion due to condensing
sulfuric acid. Secondly, these metals, particularly vanadium and
nickel, tend to form ash compounds (e.g. NiSO4 & vanadates)
that have low melting points. In the high temperature zones of the
combustion system (e.g. boiler superheaters), these ash compounds
become sticky, liquid materials that increase ash deposits and
cause high temperature corrosion.
[1001] As long as these problems are addressed, the heavy metals
can provide potential combustion improvements due to high oxidation
catalyst activity. The high-temperature corrosion problems of
traditional pet coke are partially due to char burnout near the
furnace exit, raising superheater tube metal temperatures. The
modified pet coke of the current invention mitigates this problem
in several ways: (1) highly porous coke promotes finer particle
size distribution (i.e. HGI >80), (2) Higher VCM quantity and
quality, and (3) oxidation catalyst activity of highly porous coke.
All of these factors promote char burnout before the superheater
tubes, potentially at lower excess air. As discussed previously,
the impregnated sulfur reagents of the current invention can
effectively mitigate the formation of troublesome ash constituents
and effectively remove sulfur trioxides as well as sulfur dioxide.
Consequently, modified coke of the current invention can
effectively mitigate the high-temperature corrosion, sticky ash
deposition, and cold-end corrosion. Thus, the heavy metals can be
effective oxidation catalysts without the problems of traditional
pet coke.
[1002] The activated, heavy metals in many petroleum cokes can
promote optimal combustion by catalyzing various oxidation
reactions. As discussed previously, the adsorption character of the
highly porous pet coke behaves as an oxidation catalyst in the coke
char oxidation. As the coke char oxidizes, the heavy metals,
primarily vanadium and nickel, are released from the heavy coke
compounds (e.g. porphyrins). Development of their multivalent ions
activates their high oxidation catalyst activity. That is, their
various oxidation states provide the bases of their catalytic
oxidation potential. These metal ions catalyze the coke char and
sulfur oxidation at lower temperatures and/or lower excess air
levels. Furthermore, the metal ions released in the initial char
oxidation can catalyze oxidation of VCMs in the flue gas, as well.
Overall, these catalysts create greater oxidation at lower
temperatures and lower excess air levels, producing higher
combustion efficiency and lower NOx emissions. Consequently, these
metal oxidation catalysts can be particularly helpful in low NOx
combustion modes.
[1003] Optimizing the catalytic activity of the modified pet coke's
`heavy` metals involves several factors. First, metals that are
released in the early stages of combustion provide more benefits as
oxidation catalysts in the combustion zone. That is, the longer
residence time in the combustion zone may be desired. Thus,
improved combustion of the modified coke can increase the oxidation
catalyst activity, not only in coke char combustion, but in overall
combustion, as well. Secondly, presence of certain types of
chemicals (e.g. acids) can influence the oxidation states of the
transition metals. Thus, the addition of certain chemicals can
influence the strength of oxidation catalyst. Thirdly, the presence
of certain metal compounds in the ash can catalyze oxidation
reactions downstream of the furnace high-temperature zones. Thus,
promotion of these metal compounds, to the extent possible, can
potentially continue desirable oxidation reactions (e.g. char
burnout) downstream of the furnace at lower temperatures. The
optimal catalyst activity of the heavy metals in the modified coke
will vary for each combustion system and its required operation,
including heat transfer and environmental requirements.
Consequently, the optimization of metals catalyst activity must
evaluate the trade-offs of increased catalyst activity versus other
impacts on the combustion system. One skilled in the art can
properly evaluate these trade-offs and make the appropriate
modifications to the factors, discussed above.
[1004] (5) Addition of Other Compounds:
[1005] Other types of chemical compounds can be added to further
enhance the modified pet coke of the current invention. As noted
earlier, inorganic and organic compounds can be added to the
modified pet coke via the coke quench, either by adsorption or
evaporative impregnation. That is, polar or ionic inorganic
compounds can generally be added to the modified pet coke due to
their solubility in the coke quench water. After quench water
evaporation, the inorganic compound is normally left on the
internal pores of the pet coke in molecular layers. Likewise,
non-polar, organic compounds can be generally added to the modified
pet coke via quench water. However, the deposition of this type of
compound is normally due to the modified pet coke's improved carbon
adsorption character. Thus, various compounds from either broad
class can be effectively added to modified pet coke.
[1006] (6) General Issues for Impregnation of Modified Pet
Coke:
[1007] The addition of any type of compounds to the modified coke
requires evaluation in each application. Proper consideration needs
to be given to the impacts of site-specific conditions, including
local water conditions, ambient temperatures, and coke quench &
recycle systems. In addition, there is considerable variation in
the operating conditions and procedures at the various delayed
coker installations. Pressure effects, temperature effects, and the
impact of operational procedures must be properly evaluated.
Finally, special consideration must be given to the combined
effects, when adding more than one compound. For example, there can
be chemical reactions between injected compounds or the presence of
another type of VCM or reagent can affect solubility
characteristics. One skilled in the art can make these evaluations
via engineering calculations and minor testing, if needed. Any
necessary modifications can then be made within the spirit and
intentions of the current invention.
[1008] C. Adsorption & Impregnation of Pet Coke: Enhanced Coke
Carbon Adsorption
[1009] The ability to use the carbon adsorption character of the
modified coke in various activated carbon applications was noted
earlier. As discussed previously, the adsorption characteristics
(e.g. pore structure and internal surface area) determine
adsorption capacities and potential applications. The adsorption
character can be further enhanced by the addition of various
chemical agents, based on the desired application and performance.
Various hydrocarbons and other non-polar compounds can be added to
the modified coke via adsorption. Similar to the sulfur reagents,
other chemical agents can be added via impregnation. Both
adsorption and impregnation are accomplished via the coke quench of
the decoking cycle. The adsorption and impregnation of desirable
compounds are discussed below in further detail.
[1010] (1) Addition of Sulfur Compounds:
[1011] In the prior art, elemental sulfur has been added to
activated carbon to enhance mercury removal capabilities.
Apparently, the elemental sulfur chemically reacts with mercury via
chemisorption in various applications (e.g. coal boiler flue gas).
The amount of sulfur impregnated in the internal pores of the
activated carbon is 10-20 weight percent. The impregnation
technique is apparently similar to other activated carbon
impregnation. That is, soaking or spraying of elemental sulfur onto
the surfaces of the activated carbon is completed before drying.
Drying is often performed in rotary kiln, fluid bed, multiple
hearth, or vertical furnaces. The sulfur-impregnated activated
carbon is then used to remove mercury in various vapor-phase and
liquid-phase applications. For example, sulfur-impregnated
activated carbon is injected into combustion flue gas at lower
temperatures (e.g. 350.degree. F.) to remove mercury vapors.
[1012] In a similar manner, elemental sulfur can also be
impregnated on the internal surface of the modified pet coke of the
current invention to provide an alternative means of mercury
removal. Elemental sulfur is another by-product of crude oil
processing, and already exists in a liquid form at most refineries.
Soaking or spraying of elemental sulfur (from the refinery or
otherwise) can be used to impregnate the surfaces of the modified
coke, as well. That is, the refinery elemental sulfur can be added
to crushed pet coke of the current invention prior to drying in a
suitable drier (e.g. rotary kiln, fluid bed, multiple hearth, or
other drier).
[1013] Alternatively, the elemental sulfur could be added to the
modified pet coke in the coke drum in a liquid or vapor form. The
latter is preferable to prevent pluggage of pores and provide
uniform deposition of molecular layers on the pet coke's internal
surface area. The refinery's liquid sulfur can be pumped to the
coker via heated lines at the maximum practical temperature from
the Claus Unit reactors. That is, less cooling in the condensers
after the catalytic converters may be desirable for better heat
conservation. A special heater at the base of the coke drums can
vaporize the elemental sulfurs at temperatures above 830.degree. F.
The ultimate temperature would be dependent on the pressure
required to inject the sulfur into the coke drum at the end of the
coking cycle. Prior to any steam out or cooling, the coke in the
coke drum is maintained at temperatures near the boiling point of
the elemental sulfur (e.g. 830-850.degree. F.). The vaporized
sulfur would then be injected into the bottom of the coke drum.
Heater design would provide sufficient heat to prevent premature
condensation of sulfur in the pet coke. After sufficient sulfur
impregnation, the modified pet coke is cooled in the decoking cycle
in the normal manner, preferably with minimal to no steam-out prior
to adding coke quench. Ideally, the sulfur, which is mostly
insoluble in water, would be cooled to solid form (<230.degree.
F.) without significant entrainment of sulfur in the quench water.
Realistically, some solid sulfur will be entrained in the quench
water, and may require special treatment before quench water
recycling. Excess sulfur impregnation can be required to make up
for sulfur entrained in the quench water.
[1014] Obviously, this sulfur-impregnated modified coke would not
be used as a fuel, but for specific mercury removal applications
(e.g. boiler flue gas). The amount of impregnated sulfur would
depend on the existing sulfur content of the modified coke and its
reactivity with mercury. In most cases, the existing coke sulfur
(predominately thiophenic sulfur) is not expected to react
significantly with mercury vapor, without combustion. Thus, the
amount of impregnated elemental sulfur required for effective
mercury removal is expected to be 5-25 wt. % (preferably 10-15 wt.
%).
[1015] (2) Modified Coke with Other Chemisorption Agents:
[1016] Similarly, the modified coke of the current invention can be
impregnated with other chemical agents that remove targeted
chemical compounds via chemisorption. These chemical agents should
include, but should not be limited to, iron oxide, manganese oxide,
phosphoric acid, potassium carbonate, potassium iodide, potassium
permanganate, silver, sulfur, sulfuric acid, triethylene diamine
(TEDA), zinc oxide, and salts of chromium, copper, or silver.
[1017] As noted before, various hydrocarbons and other non-polar
compounds can be added to the modified coke via adsorption. Similar
to the sulfur reagents, other chemical agents can be added via
impregnation. Both adsorption and evaporative impregnation are
accomplished via the coke quench of the decoking cycle.
[1018] (3) Optimization of Catalyst Properties:
[1019] One of the primary uses of activated carbon is a catalyst or
inert carrier material for catalytic agents. As discussed
previously, activated carbon can perform well as an oxidation
catalyst due to its ability to ionize molecular oxygen. In
addition, activated carbon can provide a key role in catalytic
reactions as an inert carrier material. Typically, the catalytic
agents are added to the activated carbon via impregnation
techniques described earlier.
[1020] Similarly, the modified coke of the current invention can be
impregnated with various catalytic agents. These catalytic agents
should include, but should not be limited to, transition metals,
noble metals, mercury chloride, and zinc acetate. Again, various
hydrocarbons and other non-polar compounds can be added to the
modified coke via adsorption. Similar to the sulfur reagents, other
chemical agents can be added via impregnation. Both adsorption and
impregnation are accomplished via the coke quench of the decoking
cycle.
[1021] D. Other Applications of Adsorption/Impregnation Techniques;
Enhanced Fuel & Carbon Adsorption Qualities
[1022] Processes and methods to improve the fuel properties,
combustion characteristics, and other qualities of pet coke have
been noted earlier in the current invention. This was accomplished
by improving its carbon adsorption characteristics and using carbon
adsorption technology to add certain desirable fuel components in
the delayed coking process. These same processes and methods can be
applied to other porous carbonaceous materials including (but not
limited to) various coals, coal wastes, other cokes, and various
activated carbons. For example, activated carbons that have served
their useful lives in carbon adsorption systems can be converted to
high quality, solid fuels for disposal in solid fuel combustion
systems. That is, VCMs, SOx sorbents, oxygen content, oxidation
catalysts, and other desirable fuel components can be uniformly
integrated into the voids in these porous, carbonaceous materials.
This can be accomplished by injecting these components into
suitable carrier media (e.g. water or air) which passes through the
activated carbons in the carbon adsorption bed or other vessel,
after one last regeneration cycle. Modification of the surface
groups (e.g. oxygen surface groups) on the activated carbon may be
necessary to adsorb polar, inorganic compounds. One skilled in the
art of carbon adsorption technology can make the appropriate
adjustments in the prescribed processes and methods of the current
invention to achieve the optimal levels of these desirable
components to provide acceptable fuel characteristics.
[1023] The impregnation techniques of the current invention can
also be used for impregnation of various chemical compounds in
other carbonaceous materials with adsorption characteristics. That
is, aqueous solutions in contact with other carbonaceous materials
can provide the means to impregnate sufficient quantities of
various chemical compounds. Theses chemical compounds include, but
should not be limited to VCMs, sulfur reagents, oxygen compounds,
ionizing compounds, and catalysts. Again, modification of the
surface groups (e.g. oxygen surface groups) on the activated carbon
may be necessary to adsorb polar, inorganic compounds.
[1024] For example, the activated carbon processes (e.g. rotary
kiln) can use quench water to add molecular layers of various
chemical compounds for improved adsorption, chemisorption,
catalysis, etc. The same basic principles of the current invention
apply to this process. Evaporation of saturated quench solution can
leave desired solute on the surface of activated carbon. However,
the deposits can be primarily on the external surface due to
resistance to flow in the internal pores. If this type of
impregnation is not sufficient, pressurized soaking with saturated
or similar solutions prior to final drying may provide the needed
deposition on internal pores.
[1025] Another example of processing carbonaceous materials with
aqueous solutions is water washing of coals. In certain coals, the
adsorption characteristics can be sufficient to adsorb various
types of VCMs in the wash water aqueous solution. Modification of
the washing process (e.g. aqueous solution through bed of crushed
coal) can enhance the adsorption of VCMs. Similarly, sulfur
reagents, oxygen compounds, and ionizing compounds can be added
with the proper solubility characteristics (e.g. Ca(OH).sub.2: more
soluble at lower temperatures).
[1026] 7. Production of Premium Petroleum Coke: Optimized Fuel
Embodiments
[1027] The various methods and embodiments of the present invention
can also be used to optimize combustion characteristics for
specific combustion applications. The following embodiment provides
a means to produce an upgraded petroleum coke that not only
achieves the basic objectives of this invention, but also optimizes
fuel characteristics to replace existing solid fuels with the least
(or lower) amount of equipment and operational modifications. As
noted earlier, one fuel can be directly substituted for an existing
fuel in a full-scale operation, if the burning characteristics are
sufficiently similar. As such, the various techniques, used in this
invention to create a premium petroleum coke, can be optimized in
many cases to produce a direct replacement fuel for existing
facilities. In this manner, a specific coker with certain design,
feedstocks, and refinery operational constraints can be modified to
produce a solid fuel with sufficiently similar combustion
characteristics as the existing solid fuel at a specific combustion
facility.
[1028] As discussed previously, various pilot-scale and laboratory
tests can effectively evaluate the burning characteristics for
various fuels. Smaller scale tests to optimize parameters are
preferable to full scale operations for various reasons, including
economics and safety. In the example for this embodiment, refinery
pilot plant studies and modified B&W burning profile tests are
used to optimize the burning characteristics of the upgraded
petroleum coke. The B&W burning profile tests have been
modified to incorporate differences in particle size distribution
attributed to differences in the solid fuels' grinding
characteristics. That is, a solid fuel with a higher Hardgrove
Grindability Index (HGI) is softer. An equivalent pulverizer can
grind these fuels to much finer particle size distributions with an
equivalent grinding energy. For example, coals with HGls of 50-70
are typically ground to 65-80% through 200-mesh (.about.74
microns). In contrast, the upgraded petroleum coke is expected to
have HGIs of 90-120 and particle size distribution of 80-95%
through 200-mesh at the same (or less) grinding energy.
[1029] Pilot plant studies can be designed to find the optimal
combination of various techniques described in this invention to
improve the fuel qualities of petroleum coke. The following
procedure can provide an adequate means to optimize the petroleum
coke fuel characteristics:
[1030] 1. Optimize design and operational parameters for the
refinery's desalting system (or system parameters in other
embodiments) to produce acceptable levels of sodium in coker feeds
& coke.
[1031] 2. Optimize coker operating temperatures (or operating
parameters of other embodiments, such as feedstock composition) to
achieve desirable levels of sponge coke crystalline structure.
[1032] 3. Compare modified B&W burning profiles of the two
fuels to evaluate adjustments in the quantity and quality of coke
VCMs needed to nearly match the burning profile of the existing
fuel.
[1033] 4. Optimize other coker operational parameters (e.g. oily
substances in water quench) to adjust the quantity and quality of
VCMs in the petroleum coke to obtain desirable combustion
characteristics.
[1034] 5. Repeat steps 3 and 4 until the critical burning
characteristics of the upgraded petroleum coke are sufficiently
similar to the burning characteristics of the existing fuel.
[1035] 6. Reproduce optimal operating conditions in the refinery
units to produce sufficient petroleum coke for a test burn in a
pilot-scale combustion system.
[1036] 7. Conduct test burn with upgraded coke and optimize
combustion design and operational parameters. Modify burners or
other equipment, as necessary, to achieve acceptable combustion
characteristics.
[1037] 8. Repeat steps 6 and 7 until evaluation of necessary
equipment and operational modifications is satisfactory. Implement
equipment and operational changes in the existing combustion
facility.
[1038] FIG. 3 shows comparisons of burning profiles for existing
coals and petroleum coke. As noted earlier, some characteristics in
the burning profile are not necessarily desirable, such as the
blips for excessive moisture and premature ignition. Other
unobvious combustion characteristics (reflected in the burning
profile's rate of release) are undesirable, including high ash
content and low porosity char. Both of these hinder oxidation and
the rate of release. Consequently, the critical combustion
characteristics in the burning profile are (1) ignition
temperatures, (2) combustion intensity (height of maximum release
rate), (3) total heat liberated (area under the profile), and (4)
temperature of oxidation termination. If these parameters are
sufficiently similar, the upgraded petroleum coke can readily
replace the existing fuel. The high char porosity, low ash content,
low moisture and high HGI of the upgraded petroleum coke tend to
shift the entire modified burning profile to the left with only
modest to moderate additions of VCM. These properties of the
upgraded petroleum coke are the primary reason that this fuel can
have better combustion characteristics than most coals, even with
significantly lower (or comparable) VCM content and/or quality.
[1039] In this manner, optimal levels of VCM quantity, coke
crystalline structure, VCM quality, and coke decontamination can be
determined. After these levels are derived, the various methods and
embodiments of the present invention (with proper consideration of
various engineering factors) can be used to optimize the upgraded
petroleum coke for specific combustion applications. The optimized
coker process control procedures (i.e. temperature controls, quench
controls, etc.) via burning profile tests is analogous to other
coker process controls that are determined by pilot plant
tests.
[1040] In conclusion, the upgraded petroleum coke of the present
invention can be readily optimized to provide sufficiently similar,
critical combustion characteristics. In this manner, the upgraded
petroleum coke can readily replace solid fuels in existing
combustion facilities with limited modifications to current design
and operation. Though the sulfur content does not significantly
affect combustion characteristics, the optimization of upgraded
petroleum coke that has been desulfurized would provide an even
more ideal fuel replacement. That is, the use of desulfurized coker
feedstocks in this optimization process can offer greater
flexibility in the optimization of environmental controls.
[1041] 8. Use of Premium Petroleum Coke: Conventional Boilers/Wet
Scrubbers
[1042] Another embodiment of the present invention is the use of
the upgraded petroleum coke in conventional, PC-fired utility
boilers with traditional particulate control devices and wet
scrubbing systems. The discussion of this embodiment includes a
basic description of a conventional utility boiler system with
traditional particulate control devices (electrostatic
precipitators, baghouses, etc.), followed by a wet scrubbing system
for the removal of sulfur oxides and/or particulates. The prior art
has been modified with (1) a retrofit addition of the flue gas
conversion reaction chamber(s) and injection system(s) and/or dry
sorbent injection system(s). The primary difference from the
exemplary embodiment is the presence of the wet scrubber. The
superior fuel characteristics of the upgraded petroleum coke are
essentially the same as the exemplary embodiment for the following
subsystems: fuel processing, combustion, heat transfer, and heat
exchange. The environmental controls section is similar, including
the modification of the existing particulate control device to a
flue gas conversion system. However, the wet scrubber provides
additional flexibility in various options that can be used to
optimize the levels of control for particulates, sulfur oxides,
carbon dioxide and other undesirable flue gas components. For
example, the operation of the wet scrubber can be used in
combination with dry sorbent injection to increase overall SOx
removal efficiencies.
[1043] A. Conventional, PC Utility Boilers w/PCD & Wet
Scrubber; Process Description
[1044] In this embodiment of the invention, a conventional,
pulverized-coal utility boiler with a traditional particulate
control device is followed by a wet scrubbing system for the
removal of sulfur oxides and/or particulates. The boiler and PCD
systems are modified in a manner similar to the exemplary
embodiment: conversion of sulfur oxides to dry particulates
upstream of the existing particulate control device(s). Thus, the
prior art has been modified to achieve this objective with Option
1: dry reagent injection system(s) and/or Option 2: a retrofit
addition of flue gas conversion reaction chamber(s) and injection
system(s). FIG. 5 shows a basic process flow diagram for this
system burning a pulverized solid fuel as the primary fuel.
Auxiliary fuel, such as natural gas or oil, is used for start-up,
low-load, and upset operating conditions. The solid fuel 200 is
introduced into the fuel processing system 202, where it is
pulverized and classified to obtain the desired particle size
distribution. A portion of combustion air (primary air) 204 is used
to suspend and convey the solid fuel particles to
horizontally-fired burners 208. Most of the combustion air
(secondary air) 210 passes through an air preheater 212, where heat
is transferred from the flue gas to the air. The heated combustion
air (up to 600.degree. F.) is distributed to the burners via an air
plenum 214. The combustion air is mixed with the solid fuel in a
turbulent zone with sufficient temperature and residence time to
initiate and complete combustion in intense flames. The intense
flames transfer heat to water-filled tubes in the high heat
capacity furnace 216, primarily via radiant heat transfer. The
resulting flue gas passes through the convection section 218 of the
boiler, where heat is also transferred to water-filled tubes,
primarily via convective heat transfer. At the entrance to the
convection section 218, certain dry reagents can be mixed with the
flue gas to convert undesirable flue gas components (e.g. sulfur
oxides) to collectible particulates (this embodiment: option 1).
The reagents 220 pass through a reagent preparation system 222 and
are introduced into the flue gas via a reagent injection system
224. Steam or air 226 is normally injected through sootblowing
equipment 228 to keep convection tubes clean of ash deposits from
the fuel and formed in the combustion process. The flue gas then
passes through the air preheater 212, supplying heat to the
combustion air.
[1045] The cooled flue gas then proceeds to the air pollution
control section of the utility boiler system. At the exit of the
air preheater, certain dry reagents can be mixed with the flue gas
to convert undesirable flue gas components (e.g. sulfur oxides) to
collectible particulates (this embodiment: option 1). The reagents
230 pass through a reagent preparation system 232 and are
introduced into the flue gas via a reagent injection system 234.
The existing particulate control device 236 (ESP, baghouse, etc.)
has been retrofitted with the addition of a reaction chamber 238
for this embodiment: option 2. Certain reagents (e.g. lime slurry)
can be prepared in a reagent preparation system 240. The reagent(s)
is dispersed into the flue gas through a special injection system
242. Sufficient mixing and residence time is provided in the
reaction chamber to convert most of the undesirable flue gas
components (e.g. sulfur oxides) to collectible particulates. These
particulates are then collected in the existing particulate control
device (PCD) 236. A bypass damper 244 is installed in the original
flue gas duct to bypass (100% open) the retrofit flue gas
conversion system, when necessary. The flue gas exits the PCD and
enters the wet scrubbing system 246. The wet scrubbing system 246
removes additional SOx and particulates. The clean flue gas then
exits the stack 248.
[1046] B. Combustion Process of the Prior Art
[1047] The combustion process of the prior art for this embodiment
is similar to the combustion process of the prior art in the
exemplary embodiment.
[1048] C. Combustion Process of the Present Invention
[1049] The combustion process of the present invention for this
embodiment may be similar to the combustion process of the present
invention in the exemplary embodiment. However, the higher density
and spherical shape of the modified fluid petroleum coke make it
more difficult to burn than modified delayed coke. Consequently,
certain parameters need to be adjusted to compensate for this
undesirable characteristic. For example, a higher VCM specification
(e.g. 20 wt. % VCM) can be necessary to achieve acceptable
combustion characteristics.
[1050] D. Environmental Controls of the Prior Art
[1051] The environmental controls of the prior art for this
embodiment may be similar to the environmental controls of the
prior art in the exemplary embodiment. Traditional particulate
control devices (PCDs) for conventional, coal-fired utility boilers
include (but should not limited to) electrostatic precipitators
(ESPs), various types of filtering systems, and wet scrubber
systems. Various wet scrubber systems have evolved to control
particulate and other emissions, including sulfur oxides. Wet
scrubbing technologies range from simple flue gas scrubbing towers
to high pressure drop, turbulent mixing devices with downstream
separation. As discussed previously. The most common type of wet
scrubbers used for U.S. utility boilers is low-pressure drop spray
tower. This type of wet scrubber system is included in this
embodiment, and was described previously. The present invention
does not claim novel wet scrubbing technology, but provides a novel
application of such technology that provides unexpected benefits
and synergism. to optimize environmental controls associated with
the combustion of petroleum coke. Therefore, further description of
readily available wet scrubbing technologies was not deemed
appropriate, at this time.
[1052] E. Environmental Controls of the Present Invention
[1053] The present invention does not claim the conventional
environmental control technologies separately, but provides
improvements and novel combinations of these technologies in
applications of the present invention. The different combinations
of these technologies are somewhat involved and provide synergism
and/or unappreciated advantages that are not suggested by the prior
art.
[1054] Similar to the exemplary embodiment, this embodiment
describes the use of existing particulate control equipment for the
control of sulfur oxides (SOx) and/or other undesirable flue gas
components. As noted previously, fuel switching, from coal to the
upgraded petroleum coke of this invention, will make available a
tremendous amount of particulate control capacity in existing
particulate control devices. Again, the existing particulate
control devices-PCDs (baghouses, electrostatic precipitators, etc.)
can be used for extensive removal of SOx and/or other undesirable
flue gas components by converting them to collectible particulates
upstream of PCDs.
[1055] The primary difference in the environmental controls of this
embodiment (versus the earlier embodiments) is the presence of the
existing wet scrubber system. The existing wet scrubber increases
the number of environmental control options and operational
flexibility. As the final environmental control system before the
flue gas exits the stack, the wet scrubber has additional impacts
on environmental emissions. The environmental controls of this
embodiment (i.e. with the wet scrubber) are also applicable to
upgraded petroleum coke from the delayed and other coking
processes.
[1056] (1) Particulates Impact:
[1057] The particulates impact of this embodiment may be similar to
the earlier embodiments. That is, the fuel switch from coal to
modified fluid coke will decrease the ash particulate loading by
>90%. However, the additional wet scrubber system in this
embodiment can provide additional reduction of particulates but can
also increase liquid entrainment in the flue gas that exits the
stack. The degrees of additional particulate reduction and increase
in liquid entrainment are expected to be minor. Both are dependent
upon the design and operation of the wet scrubber system.
[1058] (2) Sulfur Oxides Impact:
[1059] The sulfur oxides impact of this embodiment may be similar
to the exemplary embodiment. However, as noted above, the existing
wet scrubber system provides more options to achieve high levels of
sulfur oxides control. The existing wet scrubber also offers
greater operational flexibility and reliability, if a combination
of sulfur oxide controls is used.
[1060] In this embodiment, however, conversion of all the sulfur
oxides upstream of the PCD may not be desirable to optimize the
combined sulfur oxides removal. In other words, a certain portion
of the total sulfur oxides may be left unconverted and be collected
downstream of the particulate control device in the wet scrubbing
system to maximize or optimize the overall SOx removal.
Alternatively, all the sulfur oxides may be converted to
particulates and collected in the existing particulate control
device, avoiding the need for continuing the operation of the wet
scrubber. In these cases, the additional sulfur removal may not be
warranted, and the bypassing/shutdown of the wet scrubbing system
can provide substantial savings in operating costs. Alternatively,
the wet scrubber could then be converted to flue gas conversion
technology for another undesirable flue gas component, such as
CO.sub.2.
[1061] In Option 1 of this embodiment, dry sorbent injection
systems are added for additional control of sulfur oxides. As noted
in the exemplary embodiment, this unique application of this flue
gas conversion technology is expected to achieve 50-70% SOx removal
efficiency, on a long-term basis. In this embodiment, however, the
combination with the existing wet scrubber system increases the
overall sulfur oxides removal. That is, the existing wet scrubber
typically has the capability of reducing the SOx FGCT outlet
emissions by 80-95+%. The actual removal efficiency of the wet
scrubber can be reduced slightly due to the effects of lower SOx
inlet concentrations. In conclusion, a combination of this unique
flue gas conversion retrofit and wet scrubber is expected to
achieve overall SOx removal efficiencies of 95-97% (e.g.
0.7+0.85(.3)).
[1062] In Option 2 of this embodiment, retrofit reaction chamber(s)
and reagent injection system(s) are added to convert sulfur oxides
to dry particulates upstream of the existing particulate control
device(s). Since the combination of Option 1 and the existing wet
scrubber are expected to achieve such high SOx removal efficiencies
(i.e. 95-97%), replacing Option 1 with Option 2 would usually not
be cost effective. However, Option 2 can be effectively used, if
shutting down or reducing the load of the existing wet scrubber is
desirable. In this case, the combined SOx removal efficiency is
expected to be the dry scrubber efficiency (e.g. 80-90%) plus the
reduced efficiency of the existing wet scrubber multiplied by the
remaining sulfur oxide emissions from the outlet of the dry
scrubber system.
[1063] In both flue gas conversion options, minor modifications may
be necessary to maintain particulate collection efficiencies. The
particulates coming into the existing PCDs may have substantially
different properties than the particulates of the PCD's design
basis. Consequently, modifications in design and/or operating
conditions may be required. For example, flue gas conditioning or
operational changes may be appropriate to achieve desirable
resistivity characteristics, and maintain collection efficiencies
in existing electrostatic precipitators.
[1064] (3) Carbon Dioxide Impact:
[1065] The carbon dioxide impact of this embodiment may be similar
to the exemplary embodiment. However, the wet scrubber system
provides a greater opportunity to use the excess capacity of the
existing particulate control device for the control of carbon
dioxide, instead of sulfur oxides. In other words, the combination
of the dry sorbent injection (option 1) and the wet scrubber should
be sufficient SOx control to meet environmental regulations in most
cases. Therefore, the retrofit addition of a flue gas conversion
reactor/injection system (option 2) can be primarily used for
carbon dioxide control. Alternatively, Option 2 can be used for
SOx, and the wet scrubber could then be converted to flue gas
conversion technology for carbon dioxide. This latter option would
provide greater separation of technologies, and greater conversion
selectivity.
[1066] (4) Nitrogen Oxides Impact:
[1067] The nitrogen oxides impact of this embodiment may be similar
to the exemplary embodiment. However, the wet scrubber system can
provide additional reduction of nitrogen oxides. The overall impact
is expected to be relatively minor.
[1068] (5) Opacity Impact:
[1069] The opacity impact of this embodiment may be similar to the
exemplary embodiment. However, the wet scrubber system can
contribute greatly to increased opacity. That is, higher levels of
liquid entrainment can induce the agglomeration of particulates and
residual sulfur oxides, and increase opacity significantly over the
exemplary embodiment. Substantial reductions in ash particulates
and sulfur oxides, in many cases, will offset the opacity increase
due to liquid entrainment. Consequently, the liquid entrainment
remains predominantly water vapor (without impurities) and
dissipates without visual obstruction when it leaves the stack.
[1070] (6) Soild Waste Impact:
[1071] The solid waste impact of this embodiment may be very
similar to the exemplary embodiment. However, any solid waste (e.g.
sludge) generated by the use of the wet scrubber system must be
addressed. Lower utilization of the wet scrubber is expected to
substantially reduce solid wastes from the wet scrubber. As noted
earlier, reagent recycling or regeneration with Options 1 or 2 can
substantially reduce the quantity and/or quality of the solid
wastes for disposal. For most applications, the solid wastes are
expected to be substantially less than the existing system. Even
their worst case scenarios will often produce solid wastes no
greater than the existing system.
F. EXAMPLE 2
Utility Boiler with PCD and Conventional Wet Scrubber
[1072] A power utility has a conventional, pulverized-coal fired
utility boiler that currently uses a high sulfur, bituminous coal
(Illinois #6). This utility has a conventional particulate control
device (PCD) followed by a wet scrubber, achieving .about.90%
removal efficiency for sulfur oxides. Full replacement of this coal
with a high-sulfur, fluid (petroleum) coke produced by the present
invention would have the following results:
[1073] Basis=1.0.times.10.sup.9 Btu/Hr Heat Release Rate as
Input
4 Fuel Characteristics Current Coal Upgraded coke Results VCM (%
wt) 44.2 20.0 54% Lower Ash (% wt.) 10.8 0.3 97% Lower Moisture (%
wt.) 17.6 3.8 78% Lower Sulfur (% wt) 4.3 5.2 21% Higher Heating
Value (Mbtu/lb) 10.3 14.2 38% Higher Fuel Rate (MIb/Hr) 97.0 70.4
27% Lower
[1074]
5 Pollutant Emissions: Uncontrolled/Controlled Ash Particulates
(lb/MMBtu or MIb/Hr) 10.5/.53 .18/.01 98% Lower Sulfur Oxides
(lb/MMBtu or MIb/Hr) 8.4/.84 7.4/.15 82% Lower Carbon Dioxide
(lb/MMBtu or MIb/Hr) 245 214 13% Lower
[1075] This example further demonstrates the beneficial application
of the present invention. Again, the upgraded petroleum coke has
substantially lower ash and moisture contents, compared to the
existing coal. These factors contribute greatly to (1) the ability
to burn successfully with lower VCM and (2) a fuel heating value
that is 38% higher. In turn, the higher heating value requires a
27% lower fuel rate to achieve the heat release rate basis of one
billion Btu per hour in the boiler. As noted previously, this lower
fuel rate and the softer sponge coke significantly reduce the load
and wear on the fuel processing system, while increasing pulverizer
efficiency and improving combustion properties.
[1076] The ash particulate emissions (ash from the fuel) are 98%
lower than the existing coal, due to the lower ash content and
higher fuel heating value. Consequently, fuel switching to the
upgraded coke unleashes 97% of the capacity in the existing
particulate control device. This excess capacity can now be used
for the control of sulfur oxides via retrofit FGC technology.
[1077] Dry sorbent injection systems (this embodiment: option 1) is
added upstream of the existing particulate control device, along
with any associated reagent preparation and control systems, for
sulfur oxides control. In this case, the inlet SOx would be reduced
by 70% (i.e. 7.4 to 2.2 Lb/MMBtu.). The existing wet scrubber can
achieve an additional 80-90% removal (i.e. 2.2 to 0.33 Lb/MMBtu.).
Thus, the combined control efficiency of the existing wet scrubber
and the converted PCD would be >95% (e.g. 0.7+0.85(0.3)). In
this manner, the utility of converting the existing particulate
control device to dry sorbent injection represents 61% reduction in
sulfur oxides (i.e. 0.33 vs. 0.84 lb/MMBtu). This unexpected result
is achieved even though the sulfur content (5.2%) of the upgraded
petroleum coke is 21% higher than the sulfur level (4.3%) of the
Illinois bituminous coal. If this level of sulfur emissions is
sufficient to meet environmental regulations, the retrofit addition
of reaction chamber(s) and reagent injection system(s) is not
necessary.
[1078] Alternatively, a SOx dry scrubber injection/reaction vessel
(this embodiment: option 2) can be added upstream of the existing
particulate control device, along with any associated reagent
preparation and control systems. This conversion of the existing
particulate control device is assumed to achieve 90% reduction in
sulfur oxides in this case. Therefore, the uncontrolled sulfur
oxide emissions are reduced from 7.4 to 0.74 thousand pounds per
hour. If the wet scrubber is still operated, an additional 75-85+%
removal (i.e. 0.74 to 0.15 Lb/MMBtu) can be achieved. Thus, the
combined control efficiency of the existing wet scrubber and the
converted PCD would be >98% (e.g. 0.9+0.8(.1)). In this manner,
the utility of converting the existing particulate control device
to dry scrubbing represents over 82% reduction in sulfur oxides
(i.e. 0.15 vs. 0.84 Ib/MMBtu). This unexpected result is achieved
even though the sulfur content (5.2%) of the upgraded petroleum
coke is 21% higher than the sulfur level (4.3%) of the Illinois
bituminous coal.
[1079] In this example, the effective use of retrofit FGCTs for
additional reductions of carbon dioxide can be demonstrated. If
option 1 is used for sulfur oxides control, a FGCT
injection/reaction vessel can be added up stream of the existing
PCD for additional carbon dioxide control. In this case, the level
of additional carbon dioxide control is limited by (1) the
conversion of carbon dioxide to particulates and (2) the remaining
capacity of the existing PCD without exceeding environmental
regulations for particulate emissions. Alternatively, additional
particulate control capacity could be added as part of the retrofit
project. As noted earlier, the performance and capacity of the
existing PCD is not strictly on a mass weight basis, but depends on
several factors, including particulate properties. If option 2 is
used for sulfur oxide control, additional CO.sub.2 control would
likely be limited due to lack of selectivity of the FGCT reagent.
In either case, the original ash particulate capacity less the
required capacity for converted SOx (large ionic salts) may not
leave sufficient capacity to make CO.sub.2 control cost effective.
However, an upgraded petroleum coke that has been desulfurized
would offer even greater opportunities for additional CO.sub.2
control. As noted previously, the wet scrubber could also be
converted to flue gas conversion technology for carbon dioxide.
[1080] This example also illustrates significant reductions in
pollutant emissions, based solely on fuel switching. The 27% lower
fuel rate of the upgraded petroleum coke greatly contributes to
lower environmental emissions of ash particulates, sulfur oxides,
and carbon dioxide. The 98% reduction in ash particulates, noted
above, was primarily due to lower fuel ash concentration. However,
uncontrolled emissions of sulfur oxides and carbon dioxide are
significantly reduced primarily due to the 27% lower fuel rate.
That is, the sulfur content of the modified fluid coke is 21%
higher than the existing coal. Yet the upgraded petroleum coke has
12% lower uncontrolled SOx. Similarly, the upgraded petroleum coke
has 20% higher carbon content (i.e. 82.8% vs. 69.0%). Yet the
uncontrolled emissions of carbon dioxide is reduced by 13% due to
fuel switching. Similar results would be achieved by fuel switching
to an upgraded petroleum coke from a delayed coking process.
[1081] Each utility boiler will have a different set of design
conditions for converting the existing particulate control devices.
Consequently, the degree of additional control needs to be
determined on a case by case basis: including analyses of
site-specific factors of the design and operation of the existing
PCD. The conversion of each system will depend on various design
and operational parameters. Engineering factors will determine the
optimal design and level of control for SOx FGC technologies and
wet scrubbing technologies. Again, the ultimate level of additional
control for SOx and particulates will depend on (1) the efficiency
of conversion of the sulfur oxides to particulates, (2) the
efficiency of particulate collection, and (3) capacity limitations
without exceeding environmental regulations for particulate
emissions. 9. Use of Premium "Fuel-Grade" Petroleum Coke:
Additional Embodiments
[1082] Additional embodiments are described below for the various
means to effectively use the premium "fuel-grade" petroleum coke of
the present invention. Any, all, or any combination of the
embodiments, described above or below, could be used to achieve the
objects of this invention. In any combination of the embodiments,
the degree required can be less than specified here due to the
combined effects.
[1083] A. Combustion or Other End-User Systems: Additional
Embodiments
[1084] (1) All Coal-Fired Boilers:
[1085] Further embodiments of the present invention would include
the use of upgraded petroleum coke in all types of coal-fired
boilers (new or existing) regardless of furnace design, burner
orientation, or other design and operational parameters. These
combustion systems would include, but should not be limited to, low
heat capacity furnaces, cyclone furnaces, tangentially fired
furnaces/burners, non-horizontal fired burners, etc.
[1086] (2) Other Combustion Applications:
[1087] Additional embodiments of the present invention would
include all other facilities, where coals or petroleum cokes are
currently used as fuels. The present invention should not be viewed
as limited to coal-fired utility boilers, but rather may be
applicable to all combustion applications, where the enhanced
properties of the upgraded coke provide improvements, combustion
and otherwise. These combustion applications may preferably
include, but should not be limited to, industrial boilers, rotary
kilns, cement kilns, process heaters, incinerators, and fluidized
bed combustors. Also, the use of upgraded petroleum coke as a
supplemental fuel for these and other applications is anticipated
by the present invention, including biomass and/or waste combustion
facilities.
[1088] (3) Coaucoke Gasification:
[1089] In other embodiments, the present invention anticipates the
use of the upgraded petroleum coke in various coal/coke
gasification technologies. Coal gasification is a process that
converts coal from a solid to a gaseous fuel (or chemical
feedstock) through partial oxidation. Once the fuel (or chemical
feedstock) is in the gaseous state, undesirable substances, such as
sulfur compounds and ash, can be removed from the gas by
established techniques. The net result is clean, transportable fuel
(or chemical feedstock). Since coal/coke gasification is a type of
combustion (i.e. partial oxidation vs. full oxidation), many of the
same principles discussed in the present invention still apply.
Consequently, many of the improved properties of the upgraded
petroleum coke would be desirable for partial oxidation. For
example, the ability to optimize and control the quantity/quality
of the VCM and the coke crystalline structure can be very desirable
for coke gasification. Also, the ability to decontaminate the coke
in/prior to the coking process can substantially reduce the gas
clean-up requirements. The dramatically lower levels of ash and
sulfur in desulfurized petroleum coke of the present invention can
significantly reduce the capital and operating costs of the
gasification process. In this manner, the upgraded petroleum coke
can effectively replace various coals and cokes, partially or
fully, in these gasification technologies.
[1090] (4) Magnetohydrodynamic Electric Generation:
[1091] The upgraded petroleum coke can be extremely valuable as a
premium fuel for magnetohydrodynamic or MHD electric generation.
The MHD process is currently under development. Conceptually, MHD
electric generation occurs when hot, partially ionized combustion
gases (plasma) are expanded through a magnetic field. This hot gas
is produced in a coal combustor at temperatures approaching
5000.degree. F. In order to achieve these temperatures, the
combustion air must be preheated above 3000.degree. F. The gas
ionization is increased by seeding the gas with an easily ionized
material, such as potassium compounds. The spent seed compounds are
treated and recycled for economic and environmental reasons. The
major advantage of this technology is potential cycle efficiencies
in excess of 60%, compared to conventional cycle efficiencies of
35-38%. Achieving such high operating temperatures can be
accomplished more readily with the upgraded petroleum coke of the
present invention. The upgraded petroleum coke has substantially
higher heating value, lower ash, and lower moisture content versus
most coals. Also, the crystalline structure of the upgraded
petroleum coke has significantly higher porosity and can provide a
finer fuel particle size distribution. Consequently, the upgraded
coke can burn faster and cleaner, with minimal carbon residue.
These properties potentially increase the maximum flame
temperatures, as well. In addition, the quality and quantity of the
VCM in the upgraded petroleum coke can be readily formulated and
controlled to optimize combustion properties and prevent premature
combustion with very hot preheated air. Furthermore, the lower ash
content can provide economic advantage in (1) the recovery/recycle
of the seed compounds, (2) erosion prevention, and (3)
environmental controls. Finally, an upgraded petroleum coke that
has been desulfurized and/or demetallized can provide further
advantages in this combustion system and environmental
controls.
[1092] (5) Non-Combustion Applications:
[1093] Additional embodiments include any process that (1) uses
coal or petroleum coke for its physical and chemical properties (in
addition to or regardless of its fuel value), and (2) is enhanced
by the improvements of the upgraded petroleum coke of this
invention. These end-user applications include, but should not be
limited to, cement kilns, coal/coke liquefaction, coal/coke
cleaning or any process that uses coal and/or coke as a raw
material or chemical feedstock. The present invention anticipates
that the chemical and physical properties (as well as the fuel
properties and combustion characteristics) of the new formulation
of petroleum coke will offer improved operations for these types of
applications. In these applications, the modified physical and/or
chemical properties may or may not be used in conjunction with the
improved fuel properties and combustion characteristics.
[1094] B. Fuel Processing Improvements; Additional Embodiments
[1095] (1) More Than One Fuel Processing System:
[1096] In some cases, the petroleum coke end-user can have more
than one fuel processing system. Site-specific design, operational,
and/or other constraints may inhibit the fuel processing system
benefits described in the exemplary embodiment. For example, the
facility may already have or desire more than one fuel
processing/management system. Similarly, certain refining
operations and coking processes may not be capable of producing
consistent fuels due to abnormal variations in operation and coker
feedstocks. Thus, modified fuel processing systems may be required.
In either case, the present invention still provides sufficient
utility in these situations and should not be limited.
[1097] (2) Modifications to Lower Sponge Coke Specifications:
[1098] In some cases, the petroleum coke end-user can modify the
design or operation of the existing fuel processing system to
reduce the "minimum-acceptable" sponge coke specification. These
modifications include (but should not be limited to) pulverizer
type, capacity, number, and power usage characteristics. The
present invention anticipates these changes in an effort to (1)
improve the operation and reliability of the combustion system
and/or (2) reduce the degree of changes in the coker process. These
modifications can be more cost effective in certain situations.
[1099] C. Combustion Improvements; Additional Embodiments
[1100] (1) Modifications to Lower VCM Specifications:
[1101] In some cases, the petroleum coke end-user can modify the
design or operation of the existing combustion system to reduce the
"minimum-acceptable" VCM specification. These modifications include
(but should not be limited to) burner design, burner number, air
controls/distribution, furnace configuration, and boiler operation.
The present invention anticipates these changes in an effort to (1)
improve the operation and reliability of the combustion system
and/or (2) reduce the degree of changes in the coker process. These
modifications can be more cost effective in certain situations.
[1102] (2) Modifications to Lower Sponge Coke Specifications:
[1103] In some cases, the petroleum coke end-user can modify the
design and/or operation of the existing combustion system to reduce
the "minimum-acceptable" sponge coke specification. These
modifications include (but should not be limited to) burner design,
burner number, air controls/distribution, furnace configuration,
and boiler operation. The present invention anticipates these
changes in an effort to (1) improve the operation and reliability
of the combustion system and/or (2) reduce the degree of changes in
the coker process. These modifications can be more cost effective
in certain situations.
[1104] (3) Modifications to Avoid Coke Decontamination:
[1105] Another embodiment of the present invention would modify the
combustion systems or operations of the petroleum coke user, and
avoid the need for coke decontamination. Some combustion system
modifications, including modified firing techniques, firebox
temperature profiles, and combustion equipment design/operation can
alleviate the detrimental effects of certain salts and metals.
[1106] (4) New Designs that Avoid Coke Decontamination:
[1107] Another embodiment of the present invention anticipates new
designs for combustion systems with combustion, heat exchange, and
air pollution control systems that are capable of handling the
detrimental effects of the petroleum coke contaminants, including
sulfur. Thus, the need for petroleum coke decontamination can be
avoided.
[1108] D. Heat Exchange Improvements; Additional Embodiments
[1109] (1) Modifications to Avoid Coke Decontamination:
[1110] Another embodiment of the present invention would modify the
heat exchange equipment design or operation of the petroleum coke
user's facility. Some modifications in heat exchange equipment
design and/or operation can alleviate the detrimental effects of
certain mineral deposits (e.g. salts and metals). These
modifications include (but should not be limited to) better tube
metallurgy, increased soot blowing frequency, heat transfer
temperature profiles, and heat transfer equipment design/operation.
These modifications, with or without the combustion system
modifications, may reduce or eliminate the need for petroleum coke
decontamination.
[1111] (2) No Coke Decontamination Required:
[1112] Another embodiment of the present invention would
selectively use the upgraded petroleum coke in existing combustion,
heat exchange and air pollution control systems that are currently
capable of handling the detrimental effects of the petroleum coke
contaminants without coke decontamination.
[1113] E. Environmental Controls; Additional Embodiments
[1114] The new formulation of petroleum coke can provide improved
environmental benefits for a wide variety of solid-fuel
applications, both existing and new. The predominant environmental
control feature of the present invention is creating and converting
excess capacity in the existing particulate control device. This
excess capacity can be used for effective control of undesirable
flue gas components by converting them to collectible particulates
upstream of the existing particulate control device. The
pollutants, which are controlled in this manner, would include (but
not be limited to) sulfur oxides, nitrogen oxides, carbon dioxide,
metals, and air toxics. Other pollutants, defined now or in the
future, could also be controlled in this fashion. The new
formulation of petroleum coke makes this unique retrofit control
possible. In addition, the environmental issues for all embodiments
are applicable regardless of the source of the upgraded petroleum
coke (e.g. delayed coking & fluid coking).
[1115] (1) Other Flue Gas Conversion Technologies:
[1116] Various types of technologies can be used for the conversion
of gases or liquids to collectible particulates (dry or wet)
upstream of the existing particulate control devices. The exemplary
and secondary embodiments discussed the novel application of
several proven, flue gas conversion technologies that convert
sulfur oxides to dry particulates. These embodiments also noted
developing technologies for the conversion of carbon dioxide to
collectible particulates. The present invention anticipates further
development of these and other technologies to convert SOx and
CO.sub.2. These technologies may include different reagents,
reagent preparation, and reagent injection systems. The present
invention also anticipates the development of other technologies
for the conversion of nitrogen oxides, air toxics, and other
pollutants. The conversion of air toxics, such as heavy metal
vapors (e.g. mercury), is an area of great potential in the
future.
[1117] (2) Existing Dry Scrubber:
[1118] Another embodiment of the present invention is solid-fuel
combustion systems with an existing dry scrubbing system, new or
otherwise. An existing dry scrubber can be modified to use existing
particulate control capacity for additional control of undesirable
flue gas components, particularly sulfur oxides. The reagent
injection and subsequent reaction zones would need to be modified
to provide for (1) greater injection rates, (2) adequate mixing,
and (3) comparable residence time. The optimal application of these
technologies for site-specific situations can be determined through
evaluation of the engineering factors involved.
[1119] (3) Desulfurization and/or Demetallization of the Upgraded
Coke.
[1120] Another embodiment of the present invention that would
improve environmental emissions is the desulfurization and/or
demetallization of the upgraded petroleum coke. As noted above,
there are various methods to decontaminate the new formulation of
petroleum coke. Any method that decreases the sulfur content will
decrease the sulfur oxides emissions. In turn, this can make any
excess capacity in the existing particulate control devices
(including wet scrubbers) available for other types of
environmental control (e.g. flue gas conversion of CO.sub.2).
Similarly, any demetallization can decrease the emissions of
metals, particularly those that exit the combustion process in
vapor form (e.g. mercury and vanadium oxides). EXAMPLE 4
demonstrates the effective use of desulfurized petroleum coke. Note
its impact on the sulfur oxides emissions and the increased ability
to use excess PCD capacity for carbon dioxide control. In addition,
desulfurization and/or demetallization of the upgraded petroleum
coke can alleviate the need for high efficiency desalting. As
discussed previously, very low levels of sodium are not as
critical, if sulfur and vanadium levels are sufficiently low.
Furthermore, certain types of desulfurization and/or
demetallization of upgraded coke can produce very low levels of
sodium without extensive desalting. In either case, very low sodium
levels are still preferable, unless their achievement becomes
incompatible with other objectives.
[1121] (4) No Change in the Existing Environmental Control
System(s):
[1122] Another embodiment of the present invention would
selectively use the upgraded petroleum coke in existing
combustion/air pollution control systems (e.g. ESP & wet
scrubber) that are currently capable of handling the level of
sulfur in the upgraded petroleum coke of the present invention.
Many environmental regulations have pollution control limits for
sulfur oxides, written in pounds per million Btu heat release of
the fuel. Consequently, petroleum coke with a higher concentration
of sulfur can be substituted for a coal with lower sulfur
concentration without exceeding the regulatory limits. EXAMPLES 1-4
demonstrate this aspect of the present invention. The sulfur
content of the upgraded petroleum coke is equal to or greater than
the coals' sulfur contents. Yet the uncontrolled SOx emissions from
the upgraded petroleum coke are less. This alternative is possible
due to the 15-25% higher heat content of petroleum coke compared to
most coals (e.g., 13-15,00 Btu/lb vs. 10.5-13,000 Btu/lb for
bituminous coal) and its subsequent lower fuel rate.
[1123] (5) Recycling of Flue Gas Conversion Reagents:
[1124] Another embodiment of the present invention would include
extensive recycling of unreacted reagents in the FGCT systems, that
convert flue gas components to collectible particulates. Prior art
of SOx dry scrubber technology currently recycles collected flyash
into the reagent injection to increase reagent usage. However, high
ash particulates of existing fuels limit the degree of recycling.
The upgraded petroleum coke of the present invention has such low
ash particulates that greater quantities of collected flyash can be
effectively recycled to increase reagent utilization efficiencies.
Increased reagent utilization efficiencies would increase the SOx
control efficiency and reduce the solid wastes requiring disposal.
In a similar manner, the present invention can improve other flue
gas conversion technologies, as well.
[1125] (6) Regeneration of Flue Gas Conversion Reagents:
[1126] Another embodiment of the present invention involves the
regeneration of spent reagent in flue gas conversion technologies.
This regeneration can substantially reduce the make-up reagent and
waste disposal required. The regeneration process can include, but
should not be limited to, hydration of the collected flyash and
subsequent precipitation of the undesired ions (i.e. sulfates,
carbonates, etc.). In cases where slaked lime is used as the
conversion reagent, the regeneration process can greatly reduce the
carbon dioxide generated in the reagent preparation process:
limestone (calcium carbonate--CaCO.sub.4) to lime (calcium
oxide--CaO). Furthermore, the regeneration process would likely
include a purge stream to remove unacceptable levels of impurities
from the system. This purge stream would be analogous to blow down
streams in many boiler water and cooling water systems. In many
cases, this purge stream will contain a high concentration of heavy
metals, including vanadium. Various physical and/or chemical
techniques can be used to extract and purify these metals for
commercial use. Finally, the ability to continually regenerate
reagents provides the opportunity to improve the flue gas
conversion process through the use of exotic reagents; not
considered previously due to costs. In this manner, the
regeneration of conversion reagents can (1) substantially reduce
reagent and flyash disposal costs, (2) reduce C0.sub.2 emissions,
(3) create a resource for valuable metals, and (4) provide the
means to economically improve the flue gas conversion process via
the use of more exotic reagents.
[1127] (7) Salable By-Products from Fgc Technologies:
[1128] Another embodiment of the present invention improves the
quality of flue gas conversion products to provide salable
by-products and substantially reduce the solid wastes requiring
disposal. The extremely low ash particulate levels (i.e. low
impurities) provide greater opportunity to use the collected flyash
as raw materials for various products, instead of solid waste
requiring disposal. These products include, but are not limited to,
gypsum wallboard and sulfuric acid.
[1129] (8) Collection of Carbon Dioxide Generated in Reagent
Preparation: Another embodiment of the present invention
anticipates the development of carbon dioxide collection systems
for the CO.sub.2 released as a gas in the reagent preparation
systems for flue gas conversion technologies. For example, most SOx
dry scrubber systems convert calcium carbonate to calcium oxide and
carbon dioxide, that currently goes directly to the atmosphere. The
CO.sub.2 collection technologies can include (but should not be
limited to) activated carbon adsorbtion with pressure swing
regeneration. The upgraded petroleum coke of the present invention
has many desirable properties (e.g. high porosity, high HGI, etc.)
for use as the activated carbon in this CO.sub.2 collection
process. That is, upgraded petroleum coke can be readily altered to
be effectively used in this carbon adsorption application. The
activated coke eventually loses activation after numerous cycles of
use and regeneration. The deactivated coke can then be blended into
the coke fuel and subsequently burned in the combustion system.
[1130] (9) Integration of Activated Coke Removal Technologies:
[1131] Combined control of SOx and NOx emissions has been
commercially achieved in Germany and Japan using sorbent beds of
activated coke or activated char in the flue gas stream. The
activated coke/char can adsorb SO.sub.2 and catalyze the reduction
of NOx to nitrogen gas by ammonia injection. SO.sub.2 removals of
90-99+% and NOx removals of 50-80+% have been reported for low- to
medium-sulfur systems. An additional advantage of this system is
noted to be the adsorbtion of air toxics and carbon dioxide to a
limited extent. High coke consumption and high moisture content are
noted to be potential problems, particularly in high-sulfur
applications. The present invention anticipates effective
integration of this technology. Similar to the previous embodiment,
the upgraded coke of the present invention has many desirable
characteristics of the activated carbon. In many cases, the
upgraded coke can be readily modified to be effectively used as the
activated coke. Again, the coke loses activation after numerous
cycles of use and regeneration. Apparently, this occurs more
quickly in the high-sulfur applications. Deactivated coke can then
be blended into coke fuel and subsequently burned in the combustion
system.
[1132] In a similar manner, the upgraded coke of the present
invention can be used for activated carbon technologies for the
removal of air toxics (e.g. mercury), carbon dioxide, or other
undesirable flue gas components. The activated carbon technologies
for these components system can be integrated (1) fully into the
SOx/NOx activated coke system (to the extent possible), (2) share
auxiliary systems, or (3) work independently with or without the
SOX/NOx activated coke system. In any case, deactivated coke can be
blended into the coke fuel and subsequently burned in the
combustion system.
F. EXAMPLE 3
Low-Sulfur Liqnite Coal vs. Medium Sulfur Coke with Dry Sorbent
Injection
[1133] Another power utility has a conventional, pulverized-coal
fired utility boiler that currently burns a low-sulfur, lignite
coal from Texas. The existing utility has a large-capacity,
particulate control device with no sulfur oxides control. Full
replacement of this coal with a medium-sulfur, petroleum coke
produced by the present invention would have the following
results:
[1134] Basis=1.0.times.10.sup.9 Btu/Hr Heat Release Rate as
Input
6 Fuel Characteristics Current Coal Upgraded coke Results VCM (%
wt) 31.5 16.0 49% Lower Ash (% wt.) 50.4 0.3 99+% Lower Moisture (%
wt.) 34.1 0.3 99+% Lower Sulfur (% wt) 1.0 2.5 150% Higher Heating
Value (Mbtu/lb) 3.9 15.3 290% Higher Fuel Rate (MIb/Hr) 254 65.4
74% Lower
[1135]
7 Pollutant Emissions: Uncontrolled/Controlled Ash Particulates
(lb/MMBtu or 128/6.4 0.2/.01 99+% Lower MIb/Hr) Sulfur Oxides
(lb/MMBtu or MIb/Hr) 5.1 3.2/.96 37/81% Lower Carbon Dioxide
(lb/MMBtu or 315 210/150 33/52% Lower MIb/Hr)
[1136] This example further demonstrates the beneficial application
of the present invention. Again, the upgraded petroleum coke has
substantially lower ash and moisture contents, compared to the
existing coal. These factors contribute greatly to (1) the ability
to burn successfully with lower VCM and (2) a fuel heating value
that is 290% higher. In turn, the higher heating value requires a
74% lower fuel rate to achieve the heat release rate basis of one
billion Btu per hour in the boiler. As noted previously, this lower
fuel rate and the softer sponge coke substantially reduce the load
and wear on the fuel processing system, while increasing the
pulverizer efficiency and improving combustion characteristics.
[1137] The ash particulate emissions (ash from the fuel) are
>99+% lower than the existing coal, due to the lower ash content
and higher fuel heating value. Consequently, fuel switching to the
upgraded coke unleashes >99% of the capacity in the large,
existing particulate control device. Part of this excess capacity
can now be used for the control of sulfur oxides via retrofit SOx
FGC technology.
[1138] In this example, dry sorbent injection into the combustion
system with the excess capacity of the existing PCD is sufficient
to achieve the desirable sulfur oxides control. Dry sorbent is
injected in the firebox and downstream of the air preheater to
achieve 70% SOx removal. Therefore, the uncontrolled sulfur oxide
emissions are reduced from 3.2 to 0.96 thousand pounds per hour. In
this manner, the utility of converting the existing particulate
control device to dry sorbent injection represents 81% reduction in
sulfur oxides (i.e. <0.96 vs. 5.1 lb/MMBtu). This unexpected
result is achieved even though the sulfur content (2.5%) of the
upgraded petroleum coke is only 150% higher than the sulfur level
(1.0%) of the Texas lignite coal.
[1139] In this example, carbon dioxide is reduced by the lower fuel
rate and new flue gas conversion technologies (FGCT). The 74% lower
fuel rate alone reduces the carbon dioxide emissions by 32%. FGCT
processes convert carbon dioxide to dry solid particulates that can
be collected in the conventional particulate control device. The
retrofit deployment of FGC technology can be limited by the excess
capacity in the existing PCD. However, the remaining part of the
excess capacity is expected to provide further reductions of carbon
dioxide; at least 60 Mlb/Hr. In this case, the additional CO.sub.2
control from FGCT increases the combined reduction to >50%.
[1140] This example also demonstrates that the beneficial
application of the present invention does not necessarily require
the conversion of existing particulate control devices. Based
solely on fuel switching, (74% lower fuel rate and the >99%
lower ash content of the upgraded petroleum ) substantially lower
environmental emissions of ash particulates, sulfur oxides, and
carbon dioxide are achieved. Ash particulates are reduced by 99%.
The uncontrolled SOx emissions are 37% lower, even though the
sulfur content of the upgraded petroleum coke is 150% higher.
Similarly, the uncontrolled carbon dioxide emissions are reduced by
32%, even though the carbon content of the upgraded petroleum coke
is 163% higher (i.e. 88.8% vs. 33.8%). All of these pollutant
emission reductions are achieved without conversion of the existing
PCD. They come solely from switching fuel to the new formulation of
petroleum coke of the present invention.
G. EXAMPLE 4
Low Sulfur Western Coal vs. Desulfurized Petroleum Coke
[1141] Another utility has a conventional, coal-fired utility
boiler that currently uses a very low sulfur, sub-bituminous coal
from Montana. This utility has a typical particulate control device
(PCD) with no sulfur oxides emission control. Full replacement of
this coal with a desulfurized (85%) petroleum coke produced by the
present invention would have the following results:
[1142] Basis=1.0.times.10.sup.9 Btu/Hr Heat Release Rate as
Input
8 Fuel Characteristics Current Coal Upgraded coke Results VCM (%
wt) 40.8 16.0 61% Lower Ash (% wt.) 5.2 0.3 94% Lower Moisture (%
wt.) 23.4 0.3 99% Lower Sulfur (% wt) 0.44 0.65 48% Higher Heating
Value (Mbtu/lb) 9.5 15.3 61% Higher Fuel Rate (MIb/Hr) 105 65.4 38%
Lower
[1143]
9 Pollutant Emissions: Uncontrolled/Controlled Ash Particulates
(lb/MMBtu or MIb/Hr) 5.5/.3 0.2/.01 97% Lower Sulfur Oxides
(lb/MMBtu or MIb/Hr) 0.92 0.85 8% Lower Carbon Dioxide (lb/MMBtu or
MIb/Hr) 277 210/190 23/31% Lower
[1144] This example further demonstrates the beneficial application
of the present invention. Again, the upgraded petroleum coke has
substantially lower ash and moisture contents, compared to the
existing coal. These factors contribute greatly to (1) the ability
to burn successfully with lower VCM and (2) a fuel heating value
that is 61% higher. In turn, the higher heating value requires a
37% lower fuel rate to achieve the heat release rate basis of one
billion Btu per hour in the boiler. As noted previously, this lower
fuel rate and the softer sponge coke substantially reduce the load
and wear on the fuel processing system, while increasing the
pulverizer efficiency and improving combustion characteristics.
[1145] In this example, the desulfurized petroleum coke of the
present invention is sufficient to achieve very low sulfur oxide
emissions (<1.25 lb/MMBtu). In fact, the desulfurized coke
achieves 8% lower emissions (i.e. 0.85 vs. 0.92 lb/MMBtu) than this
very low sulfur, western coal, even though the desulfurized coke
has 50% higher sulfur content. Consequently, the excess capacity
created in the particulate control is available for other
undesirable flue gas components via FGC technologies.
[1146] Carbon dioxide FGC technologies with the excess capacity of
the existing PCD are expected to provide increased reductions in
carbon dioxide. The ash particulate emissions (ash from the fuel)
are >97% lower than the existing coal, due to the lower ash
content and higher fuel heating value. Consequently, fuel switching
to the upgraded coke unleashes >97% of the capacity in the
existing particulate control device. This excess capacity can now
be used for the control of carbon dioxide via retrofit FGC
technology. Carbon dioxide FGCT reagent(s) injection/reaction
vessel is added upstream of the existing particulate control
device, along with any associated reagent preparation and control
systems. The retrofit of this technology can be limited by the
excess capacity in the existing PCD. However, the excess capacity
is expected to provide further reductions of carbon dioxide; at
least 20 Mlb/Hr or 7%. In this case, the combined effect of fuel
switching and carbon dioxide FGCT is 30+% reduction in CO.sub.2
(190 vs. 275 Mlb/hr).
[1147] The desulfurized coke can be used to make most of the excess
PCD capacity (created from fuel switching) available for uses other
than SOx control. As shown in Example 3, greater reductions of
C0.sub.2 can be expected from retrofit FGC technology, if the
current coal has higher ash content and lower heating values. In
this manner, additional benefits from switching to desulfurized,
premium "fuel-qrade" petroleum coke can be achieved in those
applications.
H. EXAMPLE 5
Mixture of Existing Coal & Upgraded Petroleum Coke w/Dry
Sorbent Injection
[1148] Another power utility has a conventional, pulverized-coal
fired utility boiler that currently burns a medium-sulfur,
bituminous coal from western Pennsylvania (i.e. Pittsburgh #8). The
existing utility currently has a typical particulate control device
with no sulfur oxide emissions control. Replacement of half of this
coal (i.e. 50% by weight) with a high-sulfur petroleum coke
produced by the present invention would have the following
results:
[1149] Basis=1.0.times.10.sup.9 Btu/Hr Heat Release Rate as
Input
10 Fuel Characteristics Current Coal 50/50 Coal/Coke Results VCM (%
wt) 40.2 28.1 32% Lower Ash (% wt.) 9.1 4.7 48% Lower Moisture (%
wt.) 5.2 2.8 46% Lower Sulfur (% wt) 2.3 3.3 43% Higher Heating
Value (Mbtu/lb) 12.5 13.9 11% Higher Fuel Rate (MIb/Hr) 79.7 72.6
9% Lower
[1150]
11 Pollutant Emissions: Uncontrolled/Controlled Ash Particulates
(lb/MMBtu or Mlb/Hr) 7.3/0.7 3.8/0.4 43% Lower Sulfur Oxides
(lb/MMBtu or Mlb/Hr) 3.7/3.7 4.7/1.4 62% Lower Carbon Dioxide
(lb/MMBtu or Mlb/Hr) 216 210 3% Lower
[1151] This example further demonstrates the beneficial application
of the present invention. The 50%/50% mixture of the existing coal
and upgraded petroleum coke has significantly lower ash and
moisture contents, compared to the existing coal. These factors
contribute greatly to (1) the ability to burn successfully with
lower VCM and (2) a fuel heating value that is 11% higher. In turn,
the higher heating value requires a 9% lower fuel rate to achieve
the heat release rate basis of one billion Btu per hour in the
boiler. As noted previously, this lower fuel rate and the softer
sponge coke substantially reduce the load and wear on the fuel
processing system, while increasing the pulverizer efficiency and
improving combustion characteristics.
[1152] The ash particulate emissions (ash from the fuel) are
>43% lower than the existing coal, due to the lower ash content
and higher fuel heating value. Consequently, fuel switching to the
upgraded coke unleashes >43% of the capacity in the existing
particulate control device. This excess capacity can now be used
for the control of undesirable flue gas components via FGC
technology.
[1153] In this example, dry sorbent injection into the combustion
system with the excess capacity of the existing PCD is sufficient
to achieve the desirable sulfur oxides control. Dry sorbent is
injected in the firebox and downstream of the air preheater to
achieve 70% SOx removal. Therefore, the uncontrolled sulfur oxide
emissions are reduced from 4.7 to 1.4 thousand pounds per hour. In
this manner, the utility of converting the existing particulate
control device to dry sorbent injection SOx FGCT represents 62%
reduction in sulfur oxides (i.e. 1.4 vs. 3.2 lb/MMBtu). This
unexpected result is achieved even though the sulfur content (3.3
wt. %) of the coal/coke mixture is 43% higher than the sulfur level
(2.3%) of the existing coal.
[1154] 10. Use of Premium "Fuel-Grade" Pet Coke: Optimized
Environmental Embodiment
[1155] The various methods and embodiments of the present
invention, used to control environmental emissions, can also be
used to optimize the overall environmental controls for specific
combustion applications. In this manner, an existing combustion
facility can be modified to produce the optimal combination of
environmental controls to meet or exceed environmental regulations.
The following embodiment provides a means (1) to produce an
upgraded petroleum coke that not only achieves the basic objectives
of this invention, but (2) to also optimize the various
environmental control options for various undesirable flue gas
components and solid wastes.
[1156] As noted earlier, the upgraded petroleum coke of the present
invention has unique combustion characteristics that provides for
novel combinations of environmental control technologies. That is,
much lower ash particulates and lower fuel rates of the upgraded
petroleum coke creates tremendous capacity in the existing
particulate control device to use for the collection of various
undesirable flue gas components. However, the undesirable flue gas
components must be converted to collectible particulates (dry, wet,
or otherwise) upstream of the existing particulate control device
(PCD). Consequently, the level of control for each undesirable flue
gas component will depend on several factors: (1) Net availability
of PCD capacity, (2) Effectiveness of conversion to collectible
particulates, (3) Characteristics of conversion reagents:
Selectivity, reactivity, chemical complexity, etc, and (4) Reaction
characteristics: temperature, residence time, and mixing
requirements. The selectivity of the conversion reagent is a key
aspect, when trying to control specific undesirable flue gas
components. Otherwise, the reagent will be wasted on components
that are not intended for conversion to collectible particulates
(e.g. carbon dioxide versus sulfur oxides).
[1157] Pilot plant studies can be designed to determine the
appropriate combination of various techniques described in this
invention to optimize the control of various undesirable flue gas
components. The following procedure can provide an adequate means
to optimize the novel combinations of environmental controls of the
present invention in an existing combustion facility:
[1158] 1. Create PCD Capacity; Reduction in Ash Particulates and
Fuel Rate Due to Fuel Switching:
[1159] a. Analyze PCD capacity created: PCD design and operating
parameters
[1160] Calculate increase in collection area/flue gas ratio; due to
decrease in flue gas flow rate
[1161] Determine available capacity, based on differences in
particulate collection characteristics
[1162] b. Evaluate potential for particulate conversion
technologies w/o exceeding particulate regulations
[1163] 2. Control of Undesirable Flue Gas Components: SOx, NOx,
Carbon Dioxide, Air Toxics, Metals, etc.
[1164] a. Determine level of control required for each undesirable
flue gas component
[1165] b. Prioritize undesirable flue gas components (e.g. SOx,
CO.sub.2, NOx, air toxics, etc.)
[1166] c. Evaluate control options for each undesirable flue gas
component
[1167] Fuel replacement only: Lower fuel rate and better combustion
characteristics
[1168] Reagent injection in the furnace and/or downstream heat
exchange
[1169] Retrofit reaction chamber with reagent injection and mixing
systems
[1170] Coker feedstock decontamination and/or treatment(s) of
upgraded petroleum coke
[1171] Combination of above and/or other control options
[1172] d. Integrate all possible control combinations into various
control scenarios
[1173] e. Optimize various control scenarios to achieve control
objectives at lowest cost
[1174] This optimization process is unique for each specific
combustion facility, and can become quite complex and
time-consuming. First of all, the process must take into account
many site-specific factors, including (1) design and operation of
the existing combustion facility and particulate control devices
and (2) characteristics of the existing fuel and the replacement
upgraded petroleum coke fuel. Secondly, the optimization process
must carefully consider the relative impacts of the individual
control systems on each other, when combined in a control scenario.
For example, the reagents to convert undesirable flue gas
components to collectible particulates may interfere with each
other. Alternatively, they can create undesirable compounds (e.g.
ammonium bisulfate from reagent ammonia) that can foul, plug, or
corrode downstream system components. Finally, the mix of various
collectible particulates (e.g. calcium sulfates, ammonium
bicarbonates, etc.) can inhibit the effective use of reagent
(flyash) recycling/regeneration to improve reagent utilization and
reduce solid waste disposal. Some of these principles are
illustrated in the following embodiment of maximum environmental
protection.
[1175] The embodiment of maximum environmental protection would
likely include desulfurization and demetallization of the upgraded
petroleum coke and convert excess particulate control capacity in
the existing system for additional removal of various undesirable
flue gas components.
[1176] 1. Sulfur Oxides (SOx): Though most of the sulfur (e.g.
>85%) would be removed in the hydrodesulfurization of the coker
feedstocks, additional control of sulfur oxides can be completed by
injection of reagents in the furnace and downstream heat exchange.
In this manner, 50-70% of the remaining SOx could be converted to
collectible particulates, or >93% total reduction.
[1177] 2. Carbon Dioxide (CO.sub.2): In this embodiment, C0.sub.2
is given second priority for available PCD capacity. Carbon dioxide
would likely be converted to collectible particulates via retrofit
reaction chamber(s) with reagent injection and mixing systems.
Reaction efficiency and available PCD capacity would primarily
limit the level of CO.sub.2 removal. Additional PCD capacity could
be added as part of the retrofit project. Regeneration and recycle
of conversion reagents would likely broaden C0.sub.2 conversion
options and improve economic viability.
[1178] 3. Air Toxics: Most of the air toxic emissions associated
with combustion processes are related to the heavy metals (e.g.
mercury, vanadium, nickel, etc.) in the fuel. These air toxics
could also be converted to collectible particulates, as long as
their conversion reagents are compatible and do not interfere with
the conversion reagents for the SOx and CO.sub.2. However, the
hydrodesulfurization of coker feedstock will also decrease the
metals content of the coke. Consequently, the consumption of
available PCD capacity for air toxics removal is not expected to be
significant.
[1179] 4. Nitrogen Oxides (NOx): The nitrogen content of petroleum
coke is normally reduced by the hydrodesulfurization of the coker
feed. Nitrogen oxides are further reduced by the lower fuel rates
of the petroleum coke. Furthermore, the dramatically lower ash,
which is responsible for more uniform and stable flame, makes the
upgraded petroleum coke more susceptible to Low NOx burner designs
for lower emissions of nitrogen oxides (NOx). The remaining NOx
could also be converted to collectible particulates, but selective
noncatalytic reduction (SNCR) may be preferred and more
effective.
[1180] SNCR technologies convert NOx to molecular nitrogen via
ammonia injection into the furnace at about 1400-1800.degree. F.
However, excess ammonia needs to be minimized to avoid conversion
of SOx to ammonium bisulfate, which deposits on downstream heat
exchange
[1181] In conclusion, the present invention provides various
mechanisms of environmental protection, if needed, far beyond what
can be achieved with most coals. As noted above, the present
invention provides several embodiments to address the concerns of
environmental protection and compliance. The optimization of these
methods and embodiments can create a variety of control scenarios
to address the specific needs (compliance, economic, etc.) of a
particular combustion facility, existing or otherwise.
[1182] 11. Other Embodiments; General Issues
[1183] Finally, an additional embodiment of the present invention
may be any combination of the above embodiments. Engineering
factors will determine the optimal application for any of the above
embodiments, separately or in combination. In any combination of
the embodiments, the degree required may be less than specified
here due to the combined effects. Again, these concepts and
embodiments may be applied to delayed coking, Fluid Coking.TM.,
Flexicoking.TM. and other types of coking processes, available now
or in the future.
[1184] In view of the foregoing disclosure, it may be within the
ability of one skilled in the relevant fields to make alterations
to and substitutions in the present invention, without departing
from the spirit of the invention as reflected in the appended
claims.
Conclusion
[1185] Thus the production and use of the premium "fuel-grade"
petroleum coke, in the manner described in the present invention,
provides a superior solid fuel for conventional, coal-fired utility
boilers and various other solid-fuel combustion applications. The
environmental controls of the present invention also provide unique
technology applications with superior control capabilities.
[1186] While the above description contains many specificities,
these should not be construed as limitations on the scope of the
invention, but rather as an exemplification of the embodiments
thereof. For example, other possible variations of the invention
include those brought about through the substitution of equivalent
components or process steps. Accordingly, the scope of the
invention should be determined not by the embodiments illustrated,
but by the appended claims and their legal equivalents, the
appended claims hereby being incorporated herein by reference.
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