U.S. patent application number 10/563991 was filed with the patent office on 2006-10-19 for method for production and upgrading of oil.
Invention is credited to Kjell Moljord, Ola Olsvik.
Application Number | 20060231455 10/563991 |
Document ID | / |
Family ID | 27800810 |
Filed Date | 2006-10-19 |
United States Patent
Application |
20060231455 |
Kind Code |
A1 |
Olsvik; Ola ; et
al. |
October 19, 2006 |
Method for production and upgrading of oil
Abstract
An integrated process for production and upgrading of heavy and
extra-heavy crude oil, comprising (a) reforming of hydrocarbons
such as natural gas to produce hydrogen, CO2 and steam (b)
separating the produced hydrogen from the CO2, steam and any other
gases to give a hydrogen rich fraction and a CO2 rich fraction and
steam, (c) injecting the steam alone or in combination with the CO2
rich fraction into a reservoir containing heavy or extra heavy oil
to increase the oil recovery, and (d) upgrading/refining of the
heavy or extra heavy oil to finished products by extensive
hydroprocessing, comprising several steps of hydrocracking and
hydrotreating (sulfur, nitrogen and metals removal as well as
hydrogenation of olefins and aromatics), using the hydrogen rich
fraction.
Inventors: |
Olsvik; Ola; (Hundhamaren,
NO) ; Moljord; Kjell; (Trondheim, NO) |
Correspondence
Address: |
KIRKPATRICK & LOCKHART NICHOLSON GRAHAM LLP
535 SMITHFIELD STREET
PITTSBURGH
PA
15222
US
|
Family ID: |
27800810 |
Appl. No.: |
10/563991 |
Filed: |
July 13, 2004 |
PCT Filed: |
July 13, 2004 |
PCT NO: |
PCT/NO04/00216 |
371 Date: |
January 10, 2006 |
Current U.S.
Class: |
208/62 |
Current CPC
Class: |
C01B 2203/0244 20130101;
F25J 3/04569 20130101; C01B 2203/0415 20130101; Y02C 20/40
20200801; Y02P 20/125 20151101; C01B 2203/0475 20130101; F25J
3/04539 20130101; C01B 2203/1241 20130101; C01B 3/386 20130101;
C10G 49/007 20130101; C01B 2203/82 20130101; Y02C 10/14 20130101;
E21B 43/168 20130101; C10G 45/00 20130101; F25J 3/04121 20130101;
C01B 3/382 20130101; Y02P 30/00 20151101; F25J 3/04018 20130101;
C01B 3/52 20130101; C01B 2203/0844 20130101; Y02P 20/10 20151101;
Y02P 30/30 20151101; C01B 32/50 20170801; Y02P 90/70 20151101; E21B
43/243 20130101; C01B 2203/0283 20130101; E21B 43/164 20130101;
C01B 2203/065 20130101; C10G 47/00 20130101; E21B 43/24
20130101 |
Class at
Publication: |
208/062 |
International
Class: |
C10G 63/02 20060101
C10G063/02; C10G 57/00 20060101 C10G057/00 |
Foreign Application Data
Date |
Code |
Application Number |
Jul 16, 2003 |
NO |
2003 3230 |
Claims
1. An integrated process for production and upgrading of heavy and
extra-heavy crude oil, comprising (a) reforming of hydrocarbons to
produce gases comprised of hydrogen, CO.sub.2 and steam (b)
separating the produced hydrogen from the CO.sub.2, steam and any
other gases to give a hydrogen rich fraction and a CO.sub.2 rich
fraction and steam, (c) injecting the steam alone or in combination
with the CO.sub.2 rich fraction into a reservoir containing one of
heavy or extra heavy oil to increase the oil recovery, and (d) one
or both of upgrading and refining of the heavy or extra heavy oil
to finished products by extensive hydroprocessing, comprising a
plurality of steps of hydrocracking and hydrotreating, using the
hydrogen rich fraction.
2. The process of claim 1, wherein the reforming in step (a) is
steam reforming.
3. The process of claim 2, wherein the reforming is performed under
supercritical conditions.
4. The process of claim 1, wherein the reforming in step (a) is one
of autothermal reforming or partial oxidation.
5. The process of claim 4, wherein air is used as oxidizer in the
autothermal reformer or in the partial oxidation reactor.
6. The process of claim 3, comprising the additional step of air
separation to produce purified oxygen comprising more than 95%,
oxygen, that is used as oxidizer in the reforming.
7. The process of claim 6, wherein purified nitrogen co-produced
with the purified oxygen is injected into the reservoir together
with the CO.sub.2 rich fraction in step (d) to stimulate the oil
production.
8. The process according to claim 7 wherein CO.sub.2 produced
during the reforming process is reacted in a water gas shift
reaction to produce additional CO.sub.2 and H.sub.2.
9. The process according to claim 1 wherein the heavy or extra
heavy oil is partially upgraded in the reservoir by hydrogen
injection.
10. The process according to claim 1 wherein the heavy or extra
heavy oil is partially upgraded in a downhole upgrading unit.
11. The process according to claim 1 wherein the heavy or extra
heavy oil is upgraded on one of an offshore or onshore upgrading
facility, employing particular compact process unit design.
12. The process according to claim 1 wherein at least a part of the
heat to increase recovery of the heavy or extra heavy oil is
generated by in-situ combustion.
13. The process according to claim 1 wherein geothermal heat is
used to increase recovery and transport of the heavy or extra heavy
oil.
14. The process of claim 3 comprising the additional step of air
separation to produce purified oxygen comprising more than 98%
oxygen that is used as oxidizer in the reforming.
15. The process of claim 1 wherein the hydrocarbon reformed is
natural gas.
16. The process according to claim 15 wherein CO.sub.2 produced
during the reforming process is reacted in a water gas shift
reaction to produce additional CO.sub.2 and H.sub.2.
17. The process according to claim 1 wherein CO.sub.2 produced
during the reforming process is reacted in a water gas shift
reaction to produce additional CO.sub.2 and H.sub.2.
18. The process according to claim 5 wherein CO.sub.2 produced
during the reforming process is reacted in a water gas shift
reaction to produce additional CO.sub.2 and H.sub.2.
19. The process according to claim 7 wherein the heavy or extra
heavy oil is partially upgraded in the reservoir by hydrogen
injection.
20. The process according to claim 19 wherein the heavy or extra
heavy oil is partially upgraded in a downhole upgrading unit.
21. The process according to claim 8 wherein the heavy or extra
heavy oil is partially upgraded in a downhole upgrading unit.
22. The process according to claim 7 wherein the heavy or extra
heavy oil is upgraded on one of an offshore or onshore upgrading
facility employing a compact process unit design.
23. The process according to claim 21 wherein the heavy or extra
heavy oil is upgraded on one of an offshore or onshore upgrading
facility employing a compact process unit design.
24. The process of claim 23 wherein the compact process unit design
is compact gas reforming.
25. The process according to claim 23 wherein at least a part of
the heat to increase recovery of the heavy or extra heavy oil is
generated by in-situ combustion.
26. The process according to claim 25 wherein geothermal heat is
used to increase recovery and transport of the heavy or extra heavy
oil.
27. The process according to claim 7 wherein at least a part of the
heat to increase recovery of the heavy or extra heavy oil is
generated by in-situ combustion.
28. The process according to claim 7 wherein geothermal heat is
used to increase recovery and transport of the heavy or extra heavy
oil.
29. The process according to claim 11 wherein the particular
compact process unit design is compact gas reforming.
Description
THE FIELD OF THE INVENTION
[0001] The present invention relates to an enviromnental-friendly,
integrated process for increased production and upgrading/refining
of heavy and extra-heavy crude oil to finished products, based on
extensive use of hydrogen to maximise the yield of liquid products,
while cogenerating large amounts of steam, CO.sub.2 and optionally
N.sub.2 produced by large-scale natural gas conversion, used for
increased oil production. The finished products from
upgrading/refining of heavy/extra heavy oils will be predominantly
naphtha, kerosene, diesel and fuel oil, shipped separately or
blended.
THE BACKGROUND OF THE INVENTION
[0002] Compared to conventional oil, the utilization of heavy oil
(density<20.degree. API, viscosity>100 cP) and extra heavy
oil/bitumen (density<10.degree. API, viscosity>100000 cP) is
limited because of cost of production and upgrading. However, it is
expected that the continued need for petroleum liquids such as
transportation fuels will be met in the future more and more by
heavy oils. Hence new technologies for increased production and
more efficient upgrading/refining of heavy and extra heavy oil are
much sought for. Due to its high viscosity the primary recovery of
heavy oils by conventional methods is low. Recent developments in
production technology, such as horizontal drilling, gravity
drainage methods, non-thermal production from horizontal wells with
multilaterals, cold production of heavy oil with sand
co-production, pressure pulse flow enhancement are methods which
can increase the recovery of heavy oils at a reasonable cost. In
particular, improvements in cyclic steam stimulation (CSS) and
steam assisted gravity drainage (SAGD) have reduced the cost of
those hot production methods, but still they require large amounts
of steam (volumetric steam-to-oil ratios of 2 or higher).
[0003] Today, heavy and extra-heavy oil are converted to finished
products in two steps, where the first step referred to as
upgrading gives a synthetic crude oil which has to be further
refined to finished products. The upgrader is usually designed for
the specific heavy oil in question, while the synthetic crude with
API in the range of typically 20-35 API is an attractive feedstock
for conventional refineries, within certain limitations. The
essential feature of the heavy/extra heavy oil upgrader will be the
conversion of residue, either by carbon rejection or hydrogen
addition, to give a stable synthetic crude that might be more or
less residue-free, while the liquid fractions do not have the
quality needed for road transportation fuels. A subsequent refining
of the synthetic crude is needed to produce finished products with
the right quality, but this reprocessing is not very energy
efficient since the synthetic crude oil has to be reheated and
fractionated.
[0004] The heavy oils generally have high density and high
viscosity due to the large presence of higher boiling, polyaromatic
molecules in which the resin and asphaltene content can be as high
as 70%. As a result, these oils are low in hydrogen content, such
as for Athabasca bitumen with an ratio (atomic) H/C equal to 1.49,
compared to conventional crudes with a ratio H/C typically around
1.8, which is slightly lower than the value of the most important
refinery products, gasoline and diesel (see, J. S. Speight: "The
chemistry and technology of petroleum", 3rd ed., Marcel Dekker,
Inc., New York, 1999).
[0005] Hence, to produce valuable liquid products in high
quantities, substantial amounts of hydrogen will be needed, and
more so the heavier the crude oil. In comparison, natural gas is
rich in hydrogen with a H/C-ratio around 3.8; therefore natural gas
represents a natural source of hydrogen for upgrading of heavy oil,
as it is when refineries need additional hydrogen to close their
hydrogen balance. The attractiveness of using natural gas as
hydrogen source will depend on local factors such as availability
and cost of the natural gas.
[0006] The need for hydrogen in the refineries depends on the
feedstock and product slates, as well as the specific refinery
configuration. The general market trend is towards lighter products
such as LPG, naphtha, gasoline and diesel, putting a pressure on
the refineries with respect to upgrading of the heavier fractions.
Moreover, new specification on the sulfur content in transportation
fuels normally requires increased hydrotreating in the refineries,
a type of processing that consumes hydrogen, thereby contributing
to a hydrogen imbalance in the refineries.
[0007] Upgrading of the heavier fractions can be done either by
"carbon-rejection" type of processes such as delayed coking or
catalytic cracking, or by hydrogen addition such as hydrocracking.
The former produces "coke" which is burnt as energy input in the
processing/upgrading or sold as a product (petroleum coke), while
the latter gives a higher yield of high-value liquid products of
the kind mentioned above, at the penalty of higher hydrogen
consumption.
[0008] The particular high content of residue in heavy oils
requires particular refinery configurations to process these
crudes, and the high content of metals and carbon
residue/asphaltenes in the residue limits the use of catalytic
processes available to upgrade the heavy ends of those heavy
crudes. The hydrocracking option allows for production of
ultra-clean (low sulfur) transportation fuels of a quality in
compliance with the most stringent fuel specifications both in EU
and in the US. This will normally require a two-step hydrocracking
scheme, where the products from the residue hydrocracker must be
hydrocracked in a VGO type of hydrocracker to give the ultra-clean
transportation fuels.
[0009] In catalytic hydrocracking of residue, the metals will end
up on the catalyst, which by proper treatment can be dissolved and
the metals, mainly Vanadium and Nickel, recuperated. The sulfur
ends up as H2S which is easily captured and for example converted
to elementary sulfur by use of techniques commonly used in
refineries today. Thus, the inherent high content of impurities
such as metals and sulfur in the heavy oil, will be properly handed
in the upgrader.
[0010] Today, the change in demand pattern has created regional
lack of sufficient upgrading capacity in the refining industry, the
so-called bottom-of-the-barrel problem. This, combined with limited
hydrogen availability, will probably make it less attractive for
conventional refineries to process heavier crudes.
[0011] Heavy oils are, due to their physical properties and
particularly the high viscosity, difficult to produce and
transport. Technologies have been developed for partial upgrading
at the wellhead to make the oil transportable, as an alternative to
dilution of the viscous oil by lighter fractions such as typically
naphtha. The common solution for the Orinoco bitumen produced in
Venezuela is transport by pipeline by naphtha dilution to an
upgrader located at the coast, where the naphtha is separated from
and recycled, while the crude is partially upgraded to an
essentially residue-free synthetic crude with densities in the
range of typically 20-32API. The synthetic crude is then exported
to a conventional refinery for upgrading to finished products.
[0012] As an alternative to this conventional two-step upgrading of
heavy oil, we see potential advantages at locations where natural
gas can be made available in large quantities, to profit from large
scale hydrogen production from natural gas, by upgrading the heavy
or extra-heavy crude oil to products in one step at a dedicated
upgrader/refinery located so as to obtain maximum synergetic
effects with the hydrogen production, which will take place so as
to also obtain synergetic effects with respect to improved recovery
of heavy or extra-heavy oil from the reservoir, by the use of
energy such as steam in combination with by-products such as
CO.sub.2 and/or N.sub.2, generated by the natural gas conversion
step. The amount of hydrogen required of course depends on the
characteristics of the heavy oil, the upgrader/refinery scheme and
the types of products, but a simple mass balance demonstrates that
production of finished products from an extra-heavy oil requires so
much hydrogen that it could possibly serve as a single solution for
remote or stranded gas which then must be transported to (or close
to) the heavy oil production site. In some cases, the natural gas
could even be available as associated gas, produced with the
oil.
[0013] Due to its high viscosity the primary recovery of heavy oils
by conventional methods is low. Recent developments in production
technology, such as horizontal drilling, gravity drainage methods,
non-thermal production from horizontal wells with multilaterals,
cold production of heavy oil with sand co-production, pressure
pulse flow enhancement are methods which can increase the recovery
of heavy oils at a reasonable cost.
[0014] The reinjection of various gases into an oil reservoir in
order to enhance the oil recovery from the reservoir, and to
stabilise it, has long been known and used. In particular,
improvements in cyclic steam stimulation (CSS) and steam assisted
gravity drainage (SAGD) have reduced the cost of those hot
production methods, but still they require large amounts of steam
(volumetric steam-to-oil ratios of 2 or higher) . Gases such as
CO.sub.2, N.sub.2 and natural gas will reduce the surface tension
between gas and oil, and thus contribute to both increased recovery
and stabilisation of the reservoir. Additionally, natural gas as
such may be injected into fields where the gas does not have a net
value that exceeds the excess profits of increasing the oil
recovery in the field.
[0015] WO03/018958 relates to a combined facility for production of
gases for injection into an oil field and production of synthesis
gas for synthesis of methanol or other oxygenated hydrocarbons or
higher hydrocarbons in a synthesis loop.
[0016] Introduction of gases as mentioned above is not sufficient
to produce and transport heavy oil and extra heavy oil /bitumen
even if oil soluble gases like e.g. CO.sub.2 and methane will,
dependent on the pressure and temperature of the mixture, reduce
the viscosity somewhat.
[0017] An integrated process for gas conversion and bitumen
production is described in WO02/077124. Synthesis gas, comprising a
mixture of H.sub.2 and CO is produced from hydrocarbons, preferably
from natural gas. The natural gas may be found in the same
formations as the heavy oil or in nearby the heavy oil reservoir.
Heat from the synthesis gas production is used to produce steam for
injection into the formation to lower the viscosity of the heavy
oil by heating it. The synthesis gas is used to produce
hydrocarbons by use of a Fischer-Tropsch catalyst. At least a part
of the produced hydrocarbons is used to dilute the produced heavy
hydrocarbons to lower the viscosity to facilitate the
transportation of the oil in pipelines.
[0018] U.S. Pat. No. 4,706,751 describes another heavy oil recovery
process for the recovery of heavy oils from deep reservoirs.
Reactant streams are produced in a surface process unit. The
reactant streams, that may be e.g. H.sub.2 and O.sub.2 plus water,
or CO and steam plus water, is introduced into the well and reacted
in a catalytic reactor downhole to produce high quality steam,
H.sub.2, CO.sub.2 and any gas or vapour that are readily soluble in
the heavy oil such as methane, methanol, light hydrocarbons etc.
The reactions in the downhole reactor are exothermal and produce
heat for steam formation and heating.
[0019] Cleaning waste gas from the combustion on the production
installation can provide CO.sub.2 for injection into oil
reservoirs. In addition it has been suggested that CO.sub.2 cleaned
from the flue gas from gas power plants be reinjected by laying a
pipeline from a gas power plant to the production installation for
hydrocarbons.
[0020] The present invention aims at combining various elements of
known methods of natural gas conversion and heavy oil upgrading by
upgrading of the heavy/extra heavy oil to high value, finished
products by the use of large amounts of hydrogen generated from the
natural gas. As byproducts we obtain steam, CO.sub.2, water and
optionally N.sub.2, which can be used for enhanced recovery of the
heavy oils from the reservoir. In particular, the capture of
CO.sub.2 from the hydrogen generation plant represents a
significant potential of reduction of the CO.sub.2 emissions from
the upgrading by injection of the CO.sub.2 into underground storage
(sequestering), or injection into to reservoir to obtain enhanced
oil recovery.
SUMMARY OF THE INVENTION
[0021] According to the present invention there is provided an
integrated process for production and upgrading of heavy and
extra-heavy crude oil, comprising (a) reforming of natural gas to
produce hydrogen, CO.sub.2 and steam (b) separating the produced
hydrogen from the CO.sub.2, steam and any other gases to give a
hydrogen rich fraction and a CO.sub.2 rich fraction and steam, (c)
injecting the steam alone or in combination with the CO.sub.2 rich
fraction into the reservoir containing heavy or extra heavy oil to
increase the oil recovery, and (d) upgrading/refining of the heavy
or extra heavy oil by hydroprocessing, comprising hydrocracking and
hydrotreating using the hydrogen rich fraction in the
hydroprocessing steps. The term "hydrotreating" comprises, as used
in the present invention, removal of sulfur, nitrogen and metals as
well as hydrogenation of olefins and aromatics.
[0022] According to a preferred embodiment the reforming in step
(a) is steam reforming.
[0023] The steam reforming may be performed under supercritical
conditions.
[0024] According to another preferred embodiment the reforming in
step (a) is autothermal reforming or partial oxidation.
[0025] Air may be used as oxidizer in the autothermal reformer or
in the partial oxidation reactor.
[0026] Preferably the process comprises the additional step of air
separation to produce purified oxygen comprising more than 95%,
preferably more than 98% oxygen, that is used as oxidizer in the
reforming. The use of purified oxygen in the reforming and
separation of the reformed gases, reduces the gas volume in the
reactors and the separation units. Accordingly the volume and
building costs may be reduced and the separation of hydrogen from
the remaining gases is more effective.
[0027] Preferably, purified nitrogen co-produced with the purified
oxygen is injected into the reservoir together with the CO.sub.2
rich fraction in step (c) to stimulate the oil production. Nitrogen
is effective as pressure support in the reservoir together with the
CO.sub.2 rich fraction. It is therefore cost effective to use the
produced purified nitrogen for injection.
[0028] The process according to any of the preceding claims,
wherein CO produced during the reforming process is reacted in a
water gas shift reaction to produce additional CO.sub.2 and
H.sub.2.
[0029] The reformed gas from steam reforming, partial combustion or
autothermal reforming comprises CO. The CO is therefore preferably
converted by a water gas shift reaction to produce additional
CO.sub.2 and H.sub.2.
[0030] According to a preferred embodiment the heavy or extra heavy
oil is partially upgraded in the reservoir by hydrogen
injection.
[0031] According to a preferred embodiment the heavy or extra heavy
oil is partially upgraded in a downhole upgrading unit.
[0032] Partial upgrading of the heavy or extra heavy oil in the
reservoir makes the oil less viscous. Upgrading in the reservoir
may therefore increase the oil production, whereas both upgrading
in the reservoir and in a downhole unit will improve the
transportability of the oil
[0033] It is preferred that the heavy or extra heavy oil is
upgraded on an offshore or onshore upgrading facility.
[0034] According to a preferred embodiment at least a part of the
heat to increase recovery of the heavy or extra heavy oil is
generated by in-situ combustion.
[0035] According to an embodiment geothermal heat is used to
increase recovery and transport of the heavy or extra heavy
oil.
[0036] As an alternative to traditional two-step upgrading of heavy
oil (via synthetic crude), a potential advantages is seen at
locations where natural gas can be made available in large
quantities, to profit from large scale hydrogen production from
natural gas, by upgrading/refining the heavy or extra-heavy crude
oil to finished products in one step at a dedicated
upgrader/refinery located so as to obtain maximum synergetic
effects with the hydrogen production, which will take place so as
to also obtain synergetic effects with respect to improved recovery
of heavy or extra-heavy oil from the reservoir, by the use of
energy such as steam in combination with by-products such as CO2
and/or N2, generated by the natural gas conversion step.
BRIEF DESCRIPTION OF THE DRAWINGS
[0037] FIG. 1 is a flowchart illustrating a first preferred
embodiment, and
[0038] FIG. 2 is a flowchart illustrating a second preferred
embodiment.
DETAILED DESCRIPTION OF THE INVENTION
[0039] The present invention will be described by means of two
examples describing two preferred embodiments of the invention.
According to the present invention gas and optionally heat as steam
for injection into an oil field
EXAMPLE 1
Generation of Hydrogen by Steam Reforming of Natural Gas
[0040] FIG. 1 is a simplified flow diagram of a plant according to
a first preferred embodiment and is based on the production of 200
000 barrels per day of Zuata Heavy (API=9) oil.
[0041] Natural gas, 115 ton per hour, is introduced into a steam
reforming unit 2 via a gas line 1. Steam reforming is an
endothermal reaction. The steam reforming unit comprises a
conventional steam generation unit where water is heated and
converted into hot steam by combustion of any suitable fuel such as
natural gas, lower or higher hydrocarbons.
[0042] The natural gas from the gas line 1 and the hot steam is
reacted in one or more reactors according to the following
reactions: Steam reforming CH.sub.4+H.sub.2O.dbd.CO+3H.sub.2 Water
gas shift CO+H.sub.2O.dbd.CO.sub.2+H.sub.2
[0043] The product gas from the steam reformer is then sent to a
shift converter (one or two step) in which CO is converted to
CO.sub.2 by the water gas shift reaction, and hydrogen is then
separated by means of well known separation techniques, such as
membrane separation or separation by absorption based on the
different chemical properties of gases e.g. as described in
WO00/18681, into a hydrogen rich fraction leaving the steam
reformation unit 2 through a hydrogen line 3 and a fraction
comprising mainly CO.sub.2 and steam leaving the unit through line
4. The hydrogen rich fraction in line 3 constitutes about 35 ton
per hour, whereas about 300 ton CO.sub.2 per hour and 210 ton steam
per hour leaves the unit through line 4. This concept represents a
favourable way of CO.sub.2 capture due to the high concentration of
the CO.sub.2 in the process stream.
[0044] The preparation of a H.sub.2 rich gas and a CO.sub.2 rich
gas may be performed high pressure at supercritical conditions as
described in WO/00/18681.
[0045] The CO.sub.2 and steam is led to a unit for heavy oil
production 5 and injected to enhance the recovery of heavy oil.
Heavy oil produced in the unit for heavy oil production 5 is led
from the unit to a unit for heavy oil upgrading 7 through a heavy
oil line 6.
[0046] The heavy oil is upgraded by several steps of catalytic
hydroprocessing of the heavy or extra heavy oil using hydrogen from
line 3, by hydrocracking in combination with hydrotreating steps,
to produce valuable liquid products (distillates) from the
distillation residue, to saturate unsaturated hydrocarbons and to
remove asphaltenes, metals, nitrogen and sulphur from the finished
products.
[0047] The products from the heavy oil upgrading unit 7 leaves the
unit through a plurality of lines 8. Table 1 indicates a typical
yield structure from the unit 7. TABLE-US-00001 TABLE 1 Product Ton
per hour C-range Naphtha 200 C5-C8 Kerosine 140 C8-C12 Diesel 580
C12-C22 VGO 300 C22-380C Fuel oil, sulphur 60 380 C+
EXAMPLE 2
Generation of Hydrogen by Autothermal Reforming of Natural Gas
[0048] FIG. 2 illustrates a second preferred embodiment of the
present invention, where hydrogen for the heavy oil upgrading and
gas for injection into the reservoir is generated by autothermal
reforming (ATR) of natural gas. The example is based on the same
heavy oil and production volume of oil as Example 1.
[0049] Natural gas, 135 ton per hour (221.000 Sm.sup.3 per hour),
is introduced through a gas line 10 and O.sub.2 (from an air
separation unit) is introduced through a line 10' into an ATR unit
11. The ATR unit 11 comprises one or more autothermal reforming
reactors wherein natural gas is reformed by steam reforming
combined with partial combustion. Steam reforming is, as mentioned
above, an endothermal reaction and the energy required is supplied
from partial combustion of a part of the natural gas in the same
reactor according to the following reactions: Steam reforming
CH.sub.4+H.sub.2O.dbd.CO+3H.sub.2 Partial combustion CH.sub.4+
3/2O.sub.2.dbd.CO+2H.sub.2O
[0050] The CO is thereafter converted into CO.sub.2 according the
following reaction: Water gas shift
CO+H.sub.2O.dbd.CO.sub.2+H.sub.2
[0051] Hydrogen, 35 ton per hour, is separated from the remaining
gases as described in example 1 and a hydrogen rich fraction is led
into a hydrogen line 12 to a heavy oil upgrading unit 17.
[0052] Oxygen for the partial combustion is preferably introduced
into the reactor(s) as purified oxygen or oxygen enriched air.
Purified oxygen is preferred as the absence of the inert nitrogen
in the reactor reduces the total gas in the system and simplifies
the separation of hydrogen. The purified oxygen is generated in an
air separation unit (ASU), separating oxygen and nitrogen in two
fractions.
[0053] The nitrogen, 4.1 GSm3/y, from the ASU is led through a
nitrogen line 13 and CO.sub.2, 350 ton per hour from the ATR unit
11 is led through a line 14 to a unit for heavy oil production 15.
The steam amount available for injection is the difference between
the steam produced in the synthesis gas heat recovery section and
the steam needed for production of 70 MW power for the ASU. In the
unit for heavy oil production the nitrogen, CO.sub.2 and steam are
injected to enhance the recovery of heavy oil. Heavy oil produced
in the unit for heavy oil production 15 is led from the unit to a
unit for heavy oil upgrading 17 through a heavy oil line 16. The
products from the unit for heavy oil upgrading correspond to the
products described in Example 1.
[0054] Calculations have been carried out for a plant, according to
FIG. 2, for production of hydrogen by Auto-Thermal Reforming (ATR)
of natural gas. The hydrogen consumption will be about 35 ton/hr
(410500 Sm.sup.3/hr) for upgrading 200000 bpd heavy oil. The
natural gas needed for production of this amount of H.sub.2 will be
about 1.75 GSm3/year depending on of much flue gas and LPG that are
available in the integrated natural gas and heavy oil upgrading
complex. In this example no flue gas or LPG are used as feed to the
reforming section. By partly replacing the natural gas feed with
flue gas and LPG the natural gas consumption may be decreased by
more than 20%.
[0055] The air separation unit can deliver 23040 MTPD N.sub.2 and
3840 MTPD 02. This air separation unit requires approximately 70 MW
of power, which is delivered in the form of high-pressure steam
from the synthesis gas section. The ratio between O2 and natural
gas will be about 0.65 giving a nitrogen production of about 4.1
GSm3/year (2.34*1.75 GSm3/year)
[0056] The nitrogen is extracted at 3 bar and 0 degrees C. The gas
is compressed to 220 bars for injection (IOR). Compression requires
approximately 180 MW.
[0057] The oxygen is fed to an ATR for production of synthesis gas
from natural gas. The process operates with a steam/carbon ratio of
0.6. The temperature and pressure at the outlet from the ATR is
1030 degrees Celsius and 45 bars respectively. See Table 2 for the
natural gas composition. Note! All compositions are given on a dry
basis, i.e. without water. TABLE-US-00002 TABLE 2 Composition of
feeds to synthesis gas section Natural gas Oxygen Mole % Mole %
CH.sub.4 83.7 C.sub.2H.sub.6 5.2 C.sub.3+ 3.2 CO.sub.2 5.2 N.sub.2
+ Ar 2.7 1.0 O.sub.2 0.0 99.0 H.sub.2O 0.0 Sum 100 Total
[Sm.sup.3/hr] 221 000 190 850
[0058] TABLE-US-00003 TABLE 3 Gas composition out of the ATR ATR
outlet Mole % H.sub.2 62.9 CO 28.5 CO.sub.2 4.8 CH.sub.4 2.5
N.sub.2 + Ar 1.3 Sum 100 Total [Sm.sup.3/hr] 652000
[0059] The synthesis gas is further sent to CO shift conversion.
The gas mixture into the shift reactor can have a varying
composition depending on the conditions in the ATR (steam ratio,
pressure and temperature). One-step shift reactor may convert the
CO down to a few percent. A two-step shift converter may decrease
the CO content in the gas far below 1 percent. The gas mixture out
from the shift reactor contains significant amounts of steam. After
cooling to e.g. 40.degree. C. most of the steam will be condensed
out.
[0060] The separation of CO.sub.2 may be performed by amine washing
(e.g. ethanol amine) capturing above 90% of the CO.sub.2 in the
gas. The CO.sub.2 rich amine solution is fed to a stripping unit
where the CO.sub.2 will be liberated because of the temperature
increase and pressure reduction, further CO.sub.2 can be set free
from the amine solution by stripping with steam.
[0061] 99% of the CO.sub.2 in the gas (equivalent to 330 ton
CO.sub.2 per hour) is recovered in an MDEA process. Due to a high
concentration of CO.sub.2 in the natural gas feed, this example
includes CO.sub.2 removal prior to ATR (equivalent to 20 ton
CO.sub.2 per hour), so that the total amount of recovered CO.sub.2
is 350 ton per hour. Recovered CO.sub.2 is compressed to 220 bar,
and may if so desired be mixed with nitrogen (and eventually
available steam) prior to injection into the reservoir. This
concept also represents a favourable way of CO2 capture due to the
high concentration of the CO2 in the process stream.
[0062] The remaining gas is used in fired heaters for superheating
of steam in power production and preheating of natural gas
feeds.
[0063] The unit for heavy oil upgrading/refining may in both
examples one can envisage use the gases produced in the present
concept for both downhole upgrading and enhanced oil recovery.
Hydrogen could be used for partial downhole upgrading to obtain a
transportable oil which would be upgraded to finished products at a
nearby upgrader or exported to another refinery. A downhole unit
will reduce the loss of energy (heat) in transport lines of steam,
gases and oil. Additionally, dilution of the heavy oil to make it
flow through transport lines will be unnecessary.
[0064] The energy needed to increase the transportability of the
heavy oil in the reservoir may also be geo heat or a combination of
geo heat and energy produced in the reforming process both down
hole and in more conventional facilities off- or onshore.
[0065] It is also possible to supply heat to a reservoir by
injection air, oxygen or oxygen enriched air into the reservoir.
For reservoir temperatures above about 50.degree. C., spontaneous
combustion will usually occur soon after the start of air
injection. The heat produced by the combustion will, if the
temperature of the combustion is high enough, vaporize the water
and some of the oil to enhance the recovery of oil from the
reservoir.
[0066] Any hydrogen produced in the gas conversion part, i.e. ATR
or steam reforming units, can be used for other purposes, such as
fuel for fuel cells, and for other industrial purposes such as
production of ammonia, methanol and synthetic fuel.
* * * * *