U.S. patent application number 09/982324 was filed with the patent office on 2003-05-29 for method for increasing the net present value of fuel production while producing low sulfur fuels.
This patent application is currently assigned to Sunoco, Inc. (R&M). Invention is credited to Caron, Leroy A., Gregory, Carl, Hodgins, Judith A., Mader, Martin, McCabe, John.
Application Number | 20030098258 09/982324 |
Document ID | / |
Family ID | 25529041 |
Filed Date | 2003-05-29 |
United States Patent
Application |
20030098258 |
Kind Code |
A1 |
Gregory, Carl ; et
al. |
May 29, 2003 |
Method for increasing the net present value of fuel production
while producing low sulfur fuels
Abstract
A method is provided for increasing the net present value of
fuel production while reducing the sulfur content of one or more
fuel products produced in a refinery. The method includes
converting at least one existing reformer into a
hydrodesulfurization system; and replacing the at least one
hydrocarbon reformer with a continuous catalytic reformer.
Inventors: |
Gregory, Carl; (Sylvania,
OH) ; McCabe, John; (Chadds Ford, PA) ; Mader,
Martin; (West Chester, PA) ; Caron, Leroy A.;
(Monroeville, NJ) ; Hodgins, Judith A.; (Grosse
Ile, MI) |
Correspondence
Address: |
Robert A. Koons, Jr., Esquire
Buchanan Ingersoll PC
Eleven Penn Center
1835 Market Street, 14th Floor
Philadelphia
PA
19103-2985
US
|
Assignee: |
Sunoco, Inc. (R&M)
|
Family ID: |
25529041 |
Appl. No.: |
09/982324 |
Filed: |
October 18, 2001 |
Current U.S.
Class: |
208/89 ; 208/134;
208/213 |
Current CPC
Class: |
C10G 69/08 20130101 |
Class at
Publication: |
208/89 ; 208/134;
208/213 |
International
Class: |
C10G 069/00 |
Claims
What is claimed:
1. A method for increasing the net present value of fuel production
while reducing the sulfur content of one or more fuel products
produced in a refinery having a first production capacity,
comprising: converting at least one hydrocarbon reformer into a
desulfurization system; and replacing the at least one hydrocarbon
reformer with a modem reformer, to form a second production
capacity; wherein the net present value of the second production is
greater than the net present value of the first production
capacity.
2. The method of claim 1, wherein the desulfurization system
produces one or more fuel products with a sulfur content to 30 ppm
or less.
3. The method of claim 2, wherein the desulfurization system
reduces one or more fuel product's sulfur content to a level in
compliance with a published government standard.
4. The method of claim 1, wherein the modem reformer produces a
higher percentage of high octane gasoline per barrel in comparison
to the percentage produced by the refinery using the at least one
hydrocarbon reformer and the desulphurization system.
5. The method of claim 4, wherein the increase in the percentage of
high octane gasoline produced per barrel of is greater than about
3-5% per barrel.
6. The method of claim 5, wherein the increase in the percentage of
high octane gasoline produced per barrel is between 5% to 27%.
7. The method of claim 5, wherein the increase in the percentage of
high octane gasoline produced per barrel is from about 60-80% for
the fuel catalytic reformer to about 90-98% for the high efficiency
catalytic cracking reformer.
8. A method for reducing the sulfur content of diesel fuel and
gasoline in a fuel production process to comply with government
standards, comprising the steps of: converting at least two
catalytic reformer units into hydrodesulfurization units; adding a
continuous catalytic reformer to the refinery infrastructure; and
wherein the net present value of fuel produced by the fuel
production process using the CCR and the desulfurization systems,
is greater than the net present value of the fuel produced by the
fuel production process using at least two catalytic reformers.
9. The method of claim 8, wherein the desulfurization system
reduces the sulfur content of the gasoline produced by the refinery
to about 30 ppm or less.
10. The method of claim 8, wherein the desulfurization system
reduces the sulfur content of the diesel fuel produced by the
refinery to about 15 ppm or less.
11. The method of claim 8, wherein the hydrodesulfurization system
reduces the sulfur content of the gasoline and diesel fuel produced
by the refinery to levels in compliance with a published government
standard.
12. The method of claim 8, wherein the CCR reformer increases in
the refinery's overall output of a gasoline product, an ultra low
sulfur diesel product, produced per barrel, or both, and the
desulfurization systems enable the refinery to reduce the sulfur
content of the low sulfur gasoline and ultra low sulfur diesel
produced to about 30 ppm or less and about 15 ppm or less
respectively.
13. The method of claim 12, wherein the increase in the overall
output as a percentage of a high octane fraction produced per
barrel is greater than about 5%.
14. The method of claim 12, wherein the increase in the percentage
of high octane gasoline produced per barrel is between 5% to
27%.
15. The method of claim 12, wherein the increase in the percentage
of high octane gasoline produced per barrel is from about 60-80%
for the at least two catalytic reformers to about 90-98% for the
CCR reformer.
16. A method for producing low sulfur gasoline and ultra low sulfur
diesel in a refinery process having a gasoline production stream, a
diesel fuel production stream, or both, with said streams having as
part of their refining production streams at least one reforming
step, comprising: converting the at least one reforming step of the
gasoline production stream into one or more hydrodesulfurization
steps, and replacing the at least one reforming step in the process
with a higher efficiency catalytic reforming step, to produce an
increase in value of the production stream or streams which offsets
at least in part an initial cost for the step of converting the at
least one reforming step of the gasoline production stream into one
or more hydrodesulfurization systems.
Description
1.0 FIELD OF THE INVENTION
[0001] The present invention relates to the field of petroleum
refining. In particular, the invention relates a method of
producing low sulfur gasoline (LSG) and ultra low sulfur diesel
(ULSD) which maximizes the net present value of the gasoline
produced by a refinery.
2.0 BACKGROUND
[0002] The process of refining petroleum into gasoline, diesel fuel
and other products is widely practiced throughout the world. In
general, this process involves distilling of crude oil into a
variety of hydrocarbon fractions, reforming or purifying at least
some of the fractions to improve their performance characteristics
for their intended use, and, optionally, blending the fractions
into marketable fuel products.
[0003] Sulfur containing compounds are significant impurities in
both the crude oil and the distillation fractions, and their
removal has become particularly important in recent years. New
federal environmental regulations have imposed strict standards for
lowering the sulfur content of both gasoline and diesel sold and
used in the United States. Similar standards are already in place
in parts of Europe and in California. In short, to meet these
standards, the sulfur content of gasoline must be reduced to 30 ppm
(parts per million), while the sulfur content of diesel fuel must
be reduced to 15 ppm under the coming regulatory scheme.
[0004] Even without these regulatory requirements, the removal of
sulfur impurities is highly desirable for a number of reasons. Such
impurities can degrade catalysts and corrode machinery in later
reforming/blending steps. Moreover, they may also produce a noxious
smell when used in combustion engines, as well as contribute to
environmental problems such as acid rain.
[0005] There are a number of technologies that can be used to
remove these impurities from the hydrocarbon fractions during the
refining process. These technologies usually involve
"hydrogenation", the catalytic addition of hydrogen molecules to
the sulfur impurities to form compounds with lower boiling points
(e.g., H.sub.2S). These compounds can then be removed from the
hydrocarbon stream.
[0006] While these technologies are widely known, upgrading a
refinery to include units employing them can be extremely
expensive, requiring all new reactors, catalyst beds, piping,
heaters, towers and other equipment and infrastructure. Also, the
construction of new reactors, beds, and the like may represent an
inordinate cost to some refinery operators, especially in light of
the limited profit margins available in the commercial distribution
and sale of gasoline and diesel fuel. As a result, many refineries
are economically constrained with respect to their current
infrastructures, and capital expenses and costs to implement
desulfurization technologies are eventually borne by either the
retailers, consumers, or the refineries' shareholders.
[0007] Thus, there is a need in the art for a method of
implementing sulfur reducing technologies to produce LSG and ULSD
while increasing the net present value of fuel production in
current petroleum refineries.
3.0 SUMMARY OF THE INVENTION
[0008] The present invention relates a method of producing LSG and
ULSD while increasing the net present value of fuel production by
selectively converting existing reformers within the refinery into
hydrodesulfurization units, and replacing the converted reformers
units with modern units. This results in an increase in the amount
of gasoline produced by the refinery, an increase in the amount of
high octane rated content produced by the refinery from the
hydrocarbon fractions or streams derived from the crude petroleum,
or both. Thus, the present invention allows refinery operators and
owners to produce LSG and, optionally, ULSD in a cost effective
manner.
[0009] The method involves converting a hydrocarbon reformer into a
desulfurization system, and replacing the old reformers with state
of the art reforming technology. The net present value of the
refinery's production capacity increases relative to its first
production capacity (e.g. the refinery's production capacity with
its pre-conversion reformers, the production capacity following the
installation of new HDS units, and the like) as either an increase
in gasoline production volume or as an increase in the economic
value of the fractions or products produced therefrom. The net
capital cost for the steps of converting and replacing the at least
one hydrocarbon reformer, in light of the increase in the net
present value, is then greater than the net present value of the
first production capacity minus a net capital cost for installing a
new desulfurization system.
[0010] In one embodiment, a continuous catalytic reformer replaces
one or more of the old reformers in the refinery. The continuous
catalytic reformer increases the percentage of high octane gasoline
or blendable fraction of gasoline product produced per barrel in
comparison to the percentage produced by the refinery using the
original hydrocarbon reformer, if any, and a new desulphurization
system. The fuel products produced by a refinery's desulfurization
systems have a sulfur content which has been reduced to a level in
compliance with a published government standard.
[0011] In one embodiment, the increase in the percentage of high
octane gasoline or fraction of gasoline per barrel of crude oil is
greater than about 5% per barrel. Optionally, this increase in the
percentage of high octane gasoline or fraction of gasoline produced
per barrel can be between 5% to 27%.
[0012] In one embodiment, at least two catalytic reformer systems
are converted into desulfurization systems, and the net present
value of the fuel produced by the refinery using the continuous
catalytic reformer and the desulfurization systems, is greater than
the net present value of the fuel produced by the refinery using at
least two catalytic reformers prior to their conversion to
desulfurization systems. In one embodiment, the desulfurization
system reduces the sulfur content of the gasoline produced by the
refinery to about 30 ppm or less. Optionally, the desulfurization
system reduces the sulfur content of the diesel fuel produced by
the refinery to about 15 ppm or less.
4.0 BRIEF DESCRIPTION OF THE DRAWINGS
[0013] FIG. 1 depicts a simplified process flow diagram for the
conversion of a BTX (benzene, toluene, xylene) reformer unit into a
gasoline HDS unit.
[0014] FIG. 2 depicts a simplified process flow diagram for the
conversion of a Motor reformer unit into a diesel fuel HDS
unit.
[0015] FIG. 3 is a chart depicting projected net present value as a
function of increasing diesel fuel and gasoline prices in cents per
gallon.
5.0 DETAILED DESCRIPTION
[0016] For the purposes of this disclosure, the terms "petroleum"
and "crude oil" are interchangeably used to refer to the complex
mixture of hydrocarbons obtained from oil fields. Depending on its
geographic source, crude oil may contain about 35% to 65% (by
volume) saturated hydrocarbons and olefins, 5% to 25% aromatics,
15% to 55% naphthenes, and about 0.2 to 3% sulfur (% wt).
[0017] The terms "sulfur compounds" and "sulfur impurities" refer
to the elemental sulfur and sulfur containing organic compounds
found in crude oil and distillation fractions, which generally
include, but are not limited to, hydrogen sulfide and sulfur
containing hydrocarbons such as sulfides, thiols, and
thiophenes.
[0018] The terms "distillation" and "fractionation" are
alternatively used to refer to the step in the refining process
separating crude oil into various fractions. Each hydrocarbon
fraction thus produced has its own characteristic boiling point
range, and can be generally classified as low boiling point
fractions, middle boiling point fractions, or high boiling point
fractions. Low boiling point fractions generally include low
boiling point hydrocarbons such as methane, ethane, and propane.
Middle boiling point fractions generally include (or may be used to
produce) naphthas, kerosene, benzene, toluene, naphthalene, and
distillate fuels (i.e. diesel fuel, virgin fuel oil, and virgin
heating oil). The high boiling point fractions include (or maybe
used to produce) lubricating oils and tars, and the residue or
bottom fraction contains tar and coke.
[0019] The term "naphtha" is used to refer to the middle boiling
range hydrocarbon fraction or fractions that are major components
of gasoline, while the terms FCC naphtha and FCC gasoline refer to
naphtha which has been produced by the process of fluid catalytic
cracking.
[0020] The terms "feed" and "feedstream" refer to the stream being
sent to a reactor or treatment process while the terms "product
stream" and "outlet stream" refer to the stream after it leaves the
reactor. In a refinery, a hydrocarbon fraction may be referred to
as both a feedstock and reaction product when between multiple
steps in a treatment process. For example, the outlet stream of a
diolefin treater may become the feed for blending gasoline.
[0021] The term "reforming" refers to processes of thermally or
catalytically converting hydrocarbon fractions into fractions
having improved characteristics (e.g., a higher octane rating).
Reforming encompasses processes that include cracking,
polymerization, hydrotreating, dehydrogenation and isomerization
reactions used to improve or convert hydrocarbon fractions into
higher octane fractions. The term reformate refers to a hydrocarbon
reaction product which has been subjected to one or more reforming
steps.
[0022] The term "cracking" refers to the process of breaking higher
molecular weight (MW) hydrocarbon molecules into lower MW
molecules, typically in the presence of a catalyst. In the refining
process, cracking may be performed with reaction conditions
including elevated temperatures, elevated pressure, the presence of
a catalyst or a combination of these parameters.
[0023] The term "desulfurization" refers to any of the several
processes of chemically removing sulfur compounds from hydrocarbon
fractions. Hydrodesulfurization is an example of these processes,
as well as an example of catalytic hydrotreating.
Hydrodesulfurization typically uses a catalyst and hydrogen gas to
remove sulfur impurities by converting them to H.sub.2S and lower
molecular weight compound. Hydrotreating processes may also be used
to remove nitrogen containing compounds (e.g. amines, amides,
etc.).
[0024] The term "blending" as used herein, refers to the process of
mixing different hydrocarbon fractions into a single product,
typically the mixing of naphtha with reformates and raffinates or
other hydrocarbon fractions to produce a gasoline product with a
predetermined octane rating (an anti-knock rating system), vapor
pressure, or other desirable characteristic. Blending may take
place at the refinery, the gasoline retailer, or even at the gas
pump at a gas station.
[0025] The term "light straight run" (LSR) refers to the low to mid
range boiling point hydrocarbon fractions taken directly from a
side stream off the crude distillation column or downstream column
if a series of distillation columns is used. An LSR also typically
contains sulfur impurities.
[0026] The term "net present value" (NPV) refers to the sum of the
present values of future income (e.g. net income per year). To
reduce a future income to a present value, a discount rate
representing, inter alia, the lost opportunity costs of an
investment, is applied to the future income according to the
following formula:
NPV=I.sub.0+I.sub.n/(1+r).sup.n
[0027] Here, "I" represents the net yearly income obtained from the
investment. "I" may also be negative, e.g. when capital
expenditure, losses, or operating costs are greater than income for
a given year. The "r" represents the discount rate, and the "n"
represents the year of the income.
[0028] In the present invention, an NPV was estimated for several
refinery unit additions and modifications, with regard to meeting
the upcoming LSG and USLD regulations, including the addition of
new units, the conversion of existing units to new uses, and
upgrading equipment where appropriate. The NPVs were calculated 15
year terms and including the net initial installation costs
[0029] To effectively perform this analysis, several assumptions
and exclusions were made where appropriate in order to ensure the
consistency of the comparisons, and in order to estimate the costs
and income associated with each unit addition or modification.
These assumptions include, for the reform-to-HDS conversion
examples, that a new continuous catalytic reformer is also
installed to replace the converted reformers, with an estimated
initial investment of approximately $160 million dollars based on
past installation costs for comparable reformers. The assumptions
also include that all existing equipment and infrastructure in the
reformers being converted are in good and working condition. Also,
the NPV estimates for converting the reformers were made based upon
fiscal year 2001 budget prices, while future income estimates
assumed a 20% tax rate as well as a 12% discount rate. It is
understood that these and other assumptions/exclusions in the
analysis may be made, as long as consistency is maintained between
the comparisons, particularly the comparisons of the NPVs
associated with converting existing units to the NPVs of installing
new units.
[0030] The main process operating conditions for both the LSG and
ULSD HDS systems were also estimated in order to guide the
selection of materials and equipment. The LSG HDS main process
operating conditions, such as reactor temperatures, pressures,
hydrogen purity, etc, were based on engineering studies performed
for existing refineries, and on reviews of existing Mobil
desulfurization technologies. Desulfurization technologies reviewed
included
[0031] Exxon Mobil SCANFining IFP and Prime G.sup.+. In short, the
main process operating conditions were 350 psig (pounds per square
inch gage) reactor pressure, 700.degree. F. end-of-run temperature,
75% hydrogen purity, and 2.0 LHSV (liquid hourly space
velocity).
[0032] The ULSD HDS main process operating conditions were based
primarily on studies published by the National Petroleum Conference
(June 2000) and published data. In short, the main process
operating conditions were 800 psig reactor pressure, 750.degree. F.
end of run temperature, 75% hydrogen purity, and 1.0 LHSV. For both
the LSG and ULSD conversions, current equipment and piping
materials in each case were evaluated for use with these process
conditions.
[0033] The capital cost estimates for converting the existing
reformers in particular were derived from engineering studies which
determined what equipment and material were required to convert two
gasoline reformer units into desulfurization treatment units. The
equipment and material included as part of the estimates for each
example includes, for example, but without limitation, new or
modified reactors, towers, vessels/drums, heaters, heat exchangers,
pumps, and compressors. Flow diagrams for the converted,
reformer-to-hydrodesulfurization units (HDS) are disclosed herein
in FIG. 1 and FIG. 2.
6.0 EXAMPLES
6.1. Conversion of Existing Reformers and Installation of a
Continuous Catalytic Reformer
[0034] The conversion of existing reformer units into HDS units may
be made with only minor modifications as described below. The HDS
units generally follow typical HDS process flows. In these process
flows, a feed is mixed with hydrogen gas (e.g., recycled hydrogen
and make-up hydrogen.) The feed is then heated to reactor inlet
conditions by heat exchange with the hot reactor outlet stream, by
heat provided by a feed heater, or both. The feed then travels to
one or more reactors, where desulfurization occurs. The now hot
product stream (i.e. the outlet stream) is routed back to the heat
exchanger in order to heat the reactor feed. An air cooler reduces
the temperature of the reactor effluent, and the liquid and vapor
phases are separated in a low temperature, high pressure separator.
The liquid is sent to a stabilizer and the H.sub.2 vapor to an
amine tower, which removes the H.sub.2S in the H.sub.2 vapor.
[0035] The vapor can then be returned to the hydrogen recycle
stream. Installation of a new amine scrubber is included in the
following conversions, but it is recognized that some refineries
may be able to use existing scrubber systems. Moreover, it is
understood that alternative process flows may be used, in either
the new HDS units or in the converted reformer HDS units, depending
in part on the refineries existing equipment, available
infrastructure or particular needs. It is also understood that the
installation of metallurgical upgrades in the conversion of
reformers to HDS units (hereinafter referred to as "a conversion")
can in some instances be delayed, thus reducing initial
installation costs. However, increased monitoring would then be
required to ensure that the higher sulfur content in the feed and
increased process temperatures and pressures do not impair the
function of the piping or equipment, or cause excessive corrosion
thereof.
6.1.1. Example 1
[0036] Referring to FIG. 1, a BTX reformer with an approximate
maximum capacity of 30,000 Bbl/day of light naphtha, dehexanizer
bottoms and light unicrackate, was analyzed for conversion into an
HDS unit running approximately 42,000 Bbl/day of FCC naphtha to
produce LSG or high octane gasoline fractions (e.g. a high octane
pool). This conversion requires several expansions and additions to
the current unit, along with some material upgrades due to higher
H.sub.2S concentrations in the reactor effluent stream. A summary
of the costs for this conversion is listed in Table 1 below.
1TABLE 1 Modification or Addition Cost Estimate % of Total Cost
Estimate New stabilizer tower trays $2.5 MM 13% New amine tower
$1.5 MM 8% New diolefin reactor $1.5 MM 8% 6 new exchangers $3.5 MM
18% Modified recycle $1.5 MM 8% compressor Material Upgrades $3 MM
15% % of Total 70%
[0037] The total estimated costs for this conversion is about $20
million. As seen in Table 1, the majority of the costs in Example 1
are due to new equipment and material upgrades. These material
upgrades include relining reactors, material changes on the tube
and shell side of heat exchangers, and piping changes to prevent or
reduce corrosion.
[0038] FIG. 1 depicts a simplified process flow diagram depicting
the placement of reactors, towers, heat exchangers, pumps and
compressors in the converted unit, particularly those newly
installed or requiring material upgrades for the conversion.
[0039] Reactors
[0040] Prior to conversion into a hydrotreating unit, the BTX
reformer pretreated its liquid feedstock to remove sulfur. Before
the liquid feedstock and hydrogen mix were fed into existing
reactors they were treated at a hydro pretreater 30 for
desulfurization. The pretreater reactor 30 was used to prevent
reformer catalyst fouling by removing sulfur compounds. From the
pretreater reactor 30, it was then fed to the BTX reformer reactors
34.
[0041] The prior to conversion, the BTX reformer reactors 34
include four spherical reactors made of 11/4 Cr (chromium steel).
The conversion entails, in this instance, lining the BTX reformer
reactors with 321 stainless steel (ss). The piping between the
reactors and hot feed/effluent exchangers are also lined or
replaced with 321 ss.
[0042] Towers
[0043] The BTX reformer's stabilizer tower 38 requires a partial
retray for the design gas and liquid flows. The top 1'of the tower
38 preferably is lined with 316 ss, and contains a 347 ss
distributor. The rest of tower 38 may be carbon steel (C Stl). The
conversion in this instance also requires addition of a new amine
scrubber tower 42., which also may be made of C Stl.
[0044] Vessels/Drums
[0045] The BTX unit includes a feed surge drum 46 and a stabilizer
reflux drum 54. These drums will remain in the conversion. The
conversion also includes modification of the effluent separator 50.
Wash water may be needed to remove scale from the effluent coolers,
thus a washer boot (not depicted) will also be installed in the
conversion.
[0046] The conversion also includes three new drums. Because of the
addition of amine tower 42, the conversion includes a new carbon
steel, vertical knockout drum (not depicted) with a 316 ss
demister. The conversion also includes a new 230 ft.sup.2H.sub.2/Cl
bed 58 to remove catalyst poisons from the make-up hydrogen. The
third drum is degassing drum 62, which is fed by the amine scrubber
tower 42 bottoms.
[0047] Heaters
[0048] The BTX reformer employs four heaters, but only two will be
needed for the conversion to an HDS unit. Heaters 70, 74 supply a
fired duty of 68 MMBtu/hr and 42 MMBtu/hr respectively. For the
conversion, the first heater 70 is modified for use as a stabilizer
reboiler heater, and its burners are modified for an absorbed duty
of 28 MMBtu/hr.
[0049] The second heater 74 may optionally be used as a reactor
preheater, but a retube may be required due to the need for a
material upgrade. In particular, higher sulfur content in the feed
may require that the heater be retubed, and the piping between
heater 74 and the reactors be replaced with 9 Cr.
[0050] Heat Exchangers
[0051] In the conversion, the four BTX cold feed/effluent
exchangers 78 meet the duty requirements for the HDS unit, but the
tubes should preferably be upgraded to 321 ss due to H.sub.2S in
the effluent. Conversion of the hot feed/effluent exchangers 82
also preferably includes a tube replacement with 321 ss in the
conversion, along with a shell upgrades to 321 ss. The duty
requirements for the HDS units are not met with this set of the BTX
units exchangers, so an additional exchanger (not depicted) is
added in the conversion.
[0052] Stabilizer feed/bottom exchanger 86 needs no modifications
for the conversion, but may preferably be modified to provide
additional surface area. An additional 10,000 ft.sup.2 can be added
in parallel with exchanger 86 by adding three new exchangers (not
depicted) made of C Stl. Two new exchangers will also be added to
the stabilizer bottoms cooler 100 to provide an additional 9,600
Btu/hr. The stabilizer reboiler exchanger (not depicted) and the
surface condenser (not depicted) are abandoned in the conversion,
but the rest of the existing exchangers may remain in service
without modification, including stabilizer condenser 94 and
effluent condenser 98.
[0053] Pumps
[0054] The BTX unit's feed pump 104 has a rated capacity of 900 gpm
(gallons per minute), but the additional volume provided to the HDS
unit in the conversion will require 1260 gpm. A 500 HP motor is
installed in the conversion of the reformer's feed pump to meet the
HDS requirements. The BTX unit's stabilizer reflux pump 108 meets
all the requirements for the HDS unit, and the surface condenser
condensation pump (not depicted) is no longer needed. Two new pumps
112, 116 plus two backup pumps (not depicted) are also included in
the conversion. A centrifugal pump 112 is added for the conversion
of the stabilizer reboiler into a heater, and a piston pump 116 is
added for the wash water.
[0055] Compressors
[0056] The conversion includes modifications to the recycle
compressor 120. The reformer's recycle compressor 120 is a five
stage centrifugal compressor, with a 10,000 HP motor. This
compressor is larger than necessary for the HDS unit, and may be
destaged to replace the steam driver with a 4000 HP motor.
6.1.2. Example 2
[0057] The BTX reformer of Example 1 was also analyzed for
conversion into an HDS unit, processing an additional LSR feed. The
feed in this example includes 42,000 Bbl/day of FCC naphtha and
about 10,000 Bbl/day of LSR. However, a splitter unit (not
depicted) is included in the conversion upstream from the HDS
reactors, producing gasoline and fuel gas fractions.
[0058] A 30/70 split was assumed for the feed, therefore, only
30,000 Bbl/day of FCC naphtha will be hydrotreated.
[0059] A summary the costs for this conversion is contained in
Table 2 below.
2TABLE 2 Modification or Addition Cost Estimate % of Total Cost
Estimate 2 New splitters (splitter $6.5 MM 22% unit) 4 New
exchangers $1.5 MM 5% (splitter unit) New pumps (splitter unit) $3
MM 10% Material upgrades $5 M 17% (splitter unit) New diolefin
reactor $1.5 MM 5% (HDS unit) Modified recycle $1 MM 3% compressor
(HDS unit) New amine tower $1 MM 3% (HDS unit) Material Upgrades $7
MM 23% (HDS unit) % of Total 88%
[0060] The total cost estimate for Example 2 is $30 million
dollars, a slightly higher figure than that for Example 1. As seen
in Table 2, the additional feed requires the installation of a
splitter and its ancillary equipment. The splitter costs amount to
approximately 45% of the estimated cost, whereas the other 55% is
due to modifications and some new equipment for the desulfurization
portion of the unit. Here, the lower volume entering the HDS
reactors reduced the number of modifications to be made in this
portion of the unit.
6.1.3. Example 3: Modification of a Motor Reformer
[0061] The reformer in this example was originally designed to
process a maximum of 18,000 Bbl/day of heavy unicrackate and some
light naphtha. The modified hydrotreater unit, will run 15,000
Bbl/day of VFO to be processed into ULSD. High reactor pressures
and low space velocities will require expansions and additions to
the current unit along with some material upgrades. The estimated
cost for this conversion is $20 million dollars. As seen in Table 3
below, approximately half of the estimated costs for Example 3 stem
from the installation of a new HDS reactor.
3TABLE 3 Modification or Addition Cost Estimate % of Total Cost
Estimate New HDS reactor $9 MM 45% New H.sub.2 make-up $2 MM 10%
compressor Material upgrades $2.5 MM 13% % of Total 68%
[0062] The current reformer's reactors do not have the capacity for
the HDS unit, and were not the proper material. Therefore, all of
the original reactors were replaced with one new reactor meeting
all the HDS unit criteria. Again, material upgrades are mainly due
to the high pressure, high temperature hydrotreater loops and
higher sulfur content in the feeds. The ULSD HDS temperature and
pressure operating conditions are also higher than current
conditions in the reformer; therefore, the conversion preferably
includes the replacement of a number of metal components with
higher grade metal.
[0063] FIG. 2 is a simplified process flow diagram depicting the
placement of reactors, towers, heat exchangers, pumps and
compressors, particularly those newly installed or requiring
material upgrades.
[0064] Reactors
[0065] The Motor reformer unit has five small vertical reactors. In
this instance, the reactors are too small to meet the needs for the
HDS unit, and would all require a lining upgrade to 321 ss. Thus,
in this example, it is more cost effective to replace all of the
reformer's reactors with a new HDS reactor 124. The HDS reactor 124
has 2 beds, and a 347 ss distributor. Due to high sulfur content in
the feed, the reactor will be made of 11/4 Cr and will be 321 ss
lined. Preferably, 321 ss piping between the reactors and the
feed/effluent exchangers should also be installed. Unlike Example
1, no SHU reactor is included for Example 3.
[0066] Towers
[0067] The conversion includes no modifications to existing towers.
However, an amine scrubber 128 is added as described above.
[0068] Vessels/Drums
[0069] All existing drums and vessels will be utilized for the
conversion. No modifications are needed for the charge drum (not
depicted), steam drum (not depicted), reactor product separator
(not depicted), and the steam separator (not depicted). The
conversion does include installing a water boot in the stabilizer
overhead. Three new vessels and drums will be required as in
Example 1, a compressor knockout drum (not depicted), and
H.sub.2/Cl guard bed 136, and an amine degassing pot 140.
[0070] Heaters
[0071] The reformer has four heaters 146, but due to the exothermic
nature of the HDS reaction, only one heater is used in the HDS
system, providing a fired duty of 57,000 Btu/hr. The heater tubes
may also be upgraded from 21/4 Cr, 1 Mo to 9 Cr.
[0072] Heat Exchangers
[0073] The conversion includes retrofitting the reformer's feed
effluent exchangers 144, 148 with a new shell and tube made of 321
ss, since they are in the high pressure, high temperature
hydrotreater loop. The rest of the reformer's heat exchangers may
be used without modifications.
[0074] Pumps
[0075] The reformer's stabilizer pump (not depicted), overhead pump
(not depicted) and the spare charge pump (not depicted) will need
no modification for the conversion. However, the conversion does
include replacing the motor of the charge pump 152 to increase the
horsepower from 400 hp to 500 hp, due to the increased volume of
the HDS feed relative to the reformer's feed.
6.2. Installation of a Continuous Catalytic Reformer
[0076] Examples 1 to 3 above assume that a modem reformer unit is
built to replace the converted reformers. For example, a continuous
catalytic reformer (CCR) with a capacity of about 45,000 Bbl/day,
may be installed to replace both the Motor reformer and BTX
reformer's discussed above. The CCR's annual operating cost is
estimated to be about $10 million per year, and annual maintenance
costs of about $3 million per year. The operating and maintenance
costs of the CCR may be offset by a reduction in maintenance and
operating costs of an existing H.sub.2 plant, which can be sold or
taken off-line. Based on known CCR efficiencies, (capacity and
yields), replacing the converted reformers with the CCR results in
a $12 to $15 million/year increase in revenue. This increase in
revenue stems from an estimated 4,500 Bbl/day increase in gasoline
production, an increase in pool octane (the amount of high octane
fraction available for blending into a gasoline fuel product) and,
optionally, an increase in BTX (benzene, toluene, xylene)
production. In essence, the modern reformer increases the potential
production capacity of gasoline (per barrel) by more than about
3-5% per barrel. Depending in part on the efficiency and production
capacity of the original informer this increase my be as much as
between about 5% to 27% (per barrel). For the installation of a
modern and highly efficient continuous catalytic reformer, the
increase may be from 60-80% for the existing reformer to about
90-98% for the high efficiency catalytic cracking reformer.
However, it is recognized that these incremental increases in
efficiency may be based on the relative inefficiency of the
reformer being converted and replaced.
[0077] In the above examples, the summation of the savings,
maintenance costs, operating costs, and improved gasoline
production, results in an increase in yearly refinery income of
approximately $12 million dollars. Taking taxes and depreciation
into account, as well as the capital costs for converting the two
reformers and installing the CCR, the NPV from Equation 1 is -88.3
at current gasoline and diesel fuel prices.
6.3. Comparative Example
[0078] The capital investment required to install and bring online
new gasoline and diesel hydrodesulfurization systems is summarized
briefly in Table 3 below.
4 TABLE 3 Capital (MM$) 2002 2003 2004 2005 Total Gasoline 10 20 45
0 75 HDS unit Diesel 0 10 20 30 60 HDS unit Total 10 30 65 30
135
[0079] In essence, the initial capital cost for installing these
two systems is approximately $135 million, expended over 4 years.
In addition, starting from year one of operation, a new gasoline
HDS unit costs roughly $8 million dollars per year to operate in
order to maintain current production levels of gasoline (as low
sulfur gasoline). A new diesel fuel HDS unit costs $7.5 million per
year to operate. Once operational, an estimated $2 million would
need to be spent on HDS unit maintenance (based on the historical
maintenance costs of currently employed hydrotreating systems).
These costs would be offset by a $5 million saving increase in
revenue per year starting in 2006, as diesel fuel would no longer
be treated by the FCC unit, thus creating downstream capacity and
the potential for incremental crude throughput. Moreover, the HDS
units do not produce an increase in gasoline production, pool
octane, or BTX production. Taking taxes and depreciation into
account as in Example 3, as well as the capital investment costs
for installing new HDS units from Table 3, the installation results
in a decrease in future income of about $12 million per year. The
NPV from Equation 1 in this instance is -132.9, again, at current
gasoline and diesel fuel prices.
[0080] Thus, although the $135 million dollar initial capital
investment for new HDS units does appear to compare favorably to
the $200 million estimated for converting a BTX and Motor reformer
into HDS systems and building a modem reformer unit, when the
increased yearly income of the latter method is taken into account,
the NPV of the latter method is greater than the NPV for the new
HDS units.
[0081] FIG. 3 is a chart illustrating NPV as a function of an
incremental change in the price of diesel fuel and gasoline. As
seen in FIG. 3, a refinery implementing the inventive method would
be able to have a zero net loss from implementing the new
regulations and increasing the price of gasoline and diesel fuel by
only about 1.0 to 1.9 cents per gallon. In contrast, installing HDS
systems would require an increase of greater than 2 cents per
gallon in order for the refinery to break even.
[0082] The foregoing recitation of the invention is offered for the
purposes of illustration only. It is recognized that the
embodiments described herein may be modified or revised in various
ways without departing from the spirit and scope of the invention.
Instead, the scope of the invention is intended to be measured by
the appended claims.
* * * * *