U.S. patent application number 14/854866 was filed with the patent office on 2016-03-17 for distributed steam generation process for use in hydrocarbon recovery operations.
The applicant listed for this patent is Husky Oil Operations Limited. Invention is credited to Rodger Francesco Bernar, Bertrand Francois Mathias Burg, Lei Jia.
Application Number | 20160076346 14/854866 |
Document ID | / |
Family ID | 55454258 |
Filed Date | 2016-03-17 |
United States Patent
Application |
20160076346 |
Kind Code |
A1 |
Bernar; Rodger Francesco ;
et al. |
March 17, 2016 |
DISTRIBUTED STEAM GENERATION PROCESS FOR USE IN HYDROCARBON
RECOVERY OPERATIONS
Abstract
A method and system for producing steam for use in heavy
hydrocarbon recovery operations. In an arrangement with or without
a central processing facility and/or a plurality of well pads in
communication with the central processing facility, each well pad
is provided with equipment for separation of materials produced
from its respective wells, and steam generation equipment for that
well pad, thus allowing for simplified piping transport.
Inventors: |
Bernar; Rodger Francesco;
(Calgary, CA) ; Burg; Bertrand Francois Mathias;
(Calgary, CA) ; Jia; Lei; (Calgary, CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Husky Oil Operations Limited |
Calgary |
|
CA |
|
|
Family ID: |
55454258 |
Appl. No.: |
14/854866 |
Filed: |
September 15, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
62050908 |
Sep 16, 2014 |
|
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|
Current U.S.
Class: |
166/272.3 ;
166/268; 166/52 |
Current CPC
Class: |
E21B 43/40 20130101 |
International
Class: |
E21B 43/24 20060101
E21B043/24 |
Claims
1. A method for separating water from materials produced from a
subsurface hydrocarbon recovery operation, wherein the operation
comprises a central processing facility in fluid communication with
at least one well pad, the at least one well pad for servicing at
least one related hydrocarbon recovery well, the method comprising
the steps of: locating produced materials treatment means at the at
least one well pad; producing produced materials from the at least
one related hydrocarbon recovery well at the at least one well pad;
and treating the produced materials using the produced materials
treatment means to separate water from the produced materials.
2. The method of claim 1 further comprising the step of treating
the produced materials using the produced materials treatment means
to separate gas and/or solids and/or hydrocarbon from the produced
materials.
3. The method of claim 2, wherein the hydrocarbon is separated,
further comprising the step of transporting the hydrocarbon from
the at least one well pad to the central processing facility.
4. The method of claim 3 further comprising the step of partially
upgrading the hydrocarbon at the at least one well pad before
transporting the hydrocarbon to the central processing
facility.
5. The method of claim 2, wherein the gas is separated, further
comprising the step of treating the gas at the at least one well
pad by using gas treating means located at the at least one well
pad.
6. The method of claim 5 wherein treating the gas comprises
reducing sulphur content of the gas.
7. The method of claim 2, wherein the hydrocarbon is separated,
further comprising the step of diluting the hydrocarbon with a
diluent at the at least one well pad before transporting the
hydrocarbon to the central processing facility.
8. The method of claim 1 further comprising the step of
demulsifying the produced materials with a demulsifier to enable
separation of the produced materials.
9. The method of claim 1 further comprising the steps of feeding
the water to steam generation means located at the at least one
well pad and generating steam from the water.
10. The method of claim 9 further comprising the step of injecting
the steam into the at least one related hydrocarbon recovery
well.
11. A method for generating steam for use in a subsurface
hydrocarbon recovery operation, wherein the operation comprises a
central processing facility in fluid communication with at least
one well pad, the at least one well pad for servicing at least one
related hydrocarbon recovery well, the method comprising the steps
of: locating produced materials treatment means and steam
generation means at the at least one well pad; producing produced
materials from the at least one related hydrocarbon recovery well
at the at least one well pad; treating the produced materials using
the produced materials treatment means to separate water from the
produced materials; feeding the water to the steam generation means
to generate steam from the water; and injecting the steam into the
at least one related hydrocarbon recovery well.
12. The method of claim 11 further comprising the step of treating
the produced materials using the produced materials treatment means
to separate gas and/or solids and/or hydrocarbon from the produced
materials.
13. The method of claim 12, wherein the hydrocarbon is separated,
further comprising the step of transporting the hydrocarbon from
the at least one well pad to the central processing facility.
14. The method of claim 13, further comprising the step of
partially upgrading the hydrocarbon at the at least one well pad
before transporting the hydrocarbon to the central processing
facility.
15. The method of claim 12, wherein the gas is separated, further
comprising the step of treating the gas at the at least one well
pad by using gas treating means located at the at least one well
pad.
16. The method of claim 15 wherein treating the gas comprises
reducing sulphur content of the gas.
17. The method of claim 13, further comprising the step of diluting
the hydrocarbon with a diluent at the at least one well pad before
transporting the hydrocarbon to the central processing
facility.
18. The method of claim 11 further comprising the step of
demulsifying the produced materials with a demulsifier to enable
separation of the produced materials.
19. A system for steam generation for use in subsurface hydrocarbon
recovery, the system comprising: a central processing facility; at
least one well pad in fluid communication with the central
processing facility, wherein the at least one well pad is adjacent
to at least one related hydrocarbon recovery well, the at least one
related hydrocarbon recovery well for producing produced materials;
produced materials treatment means at the at least one well pad
configured to separate water from the produced materials produced
from the at least one hydrocarbon recovery well; steam generation
means at the at least one well pad for receiving the water and
generating steam from the water; and steam injection means for
injecting the steam into the at least one related hydrocarbon
recovery well.
20. The system of claim 19 wherein the produced materials treatment
means are configured to separate gas and/or solids and/or
hydrocarbon from the produced materials.
21. The system of claim 20 wherein the produced materials treatment
means are configured to separate the hydrocarbon from the produced
materials, further comprising pipeline means for transporting the
hydrocarbon from the at least one well pad to the central
processing facility.
22. The system of claim 21 further comprising an upgrading plant at
the at least one well pad for partially upgrading the hydrocarbon
before transporting the hydrocarbon to the central processing
facility.
23. The system of claim 20 wherein the produced materials treatment
means are configured to separate gas from the produced materials,
further comprising gas treating means located at the at the least
one well pad for treating the gas at the at least one well pad.
24. The system of claim 23 wherein the gas treating means are for
reducing sulphur content of the gas.
25. The system of claim 21 further comprising a diluent source for
diluting the hydrocarbon with a diluent at the at least one well
pad before transporting the hydrocarbon to the central processing
facility.
26. The system of claim 19 further comprising a demulsifier source
for providing demulsifier to the produced materials to enable
separation of the produced materials.
Description
CROSS REFERENCE TO RELATED APPLICATION
[0001] This application claims the benefit of and priority to U.S.
Provisional Patent Application Ser. No. 62/050,908, filed Sep. 16,
2014, entitled "Distributed Steam Generation Process for Use in
Hydrocarbon Recovery Operations," the contents of which are
incorporated herein in its entirety for all purposes.
FIELD OF THE INVENTION
[0002] The invention relates to thermal recovery methods and
systems for heavy hydrocarbon deposits, and specifically to such
methods and systems requiring steam injection to mobilize the
deposits.
BACKGROUND
[0003] In the field of subsurface hydrocarbon production, it is
known to employ various stimulation procedures and techniques to
enhance production. For example, in the case of heavy oil and
bitumen housed in subsurface reservoirs, conventional drive
mechanisms may be inadequate to enable production to surface, and
it is well known to therefore inject steam or steam-solvent
mixtures to make the heavy hydrocarbon more amenable to movement
within the reservoir permeability pathways, by heating the
hydrocarbon and/or mixing it with lighter hydrocarbons or hot
water.
[0004] In steam-assisted gravity drainage ("SAGD") and cyclic steam
stimulation ("CSS") hydrocarbon recovery operations, steam is
generated at surface by steam generation units and injected
downhole into a well, where it is subsequently introduced into an
underground hydrocarbon formation in which the well lies, after
which the steam warms bitumen and oil within the formation.
Thus-warmed hydrocarbon within the formation is mobilized and moves
or is drawn toward the well, where it is then collected and
produced to surface. The steam, when contacting cooler subterranean
bitumen and oil, typically condenses to water, releasing latent
heat of condensation and thereby effectively transferring heat to
the oil/bitumen.
[0005] Due to the foregoing condensation of injected steam to
water, and also by reason that underground formations typically
contain amounts of water in the form of brine or the like, water is
typically produced to surface with the recovered hydrocarbon.
Because proximate sources of water for producing steam for
injection downhole are often in very short supply, or their use
prevented due to governmental restrictions, it is very desirable to
use produced water to generate steam. Not only is such water
(although contaminated) available at site, but by generating steam
from produced water the disposal costs (which are also impacted by
regulatory limitations) of such contaminated produced water is
reduced.
[0006] Typically, water that is produced to surface with the
collected hydrocarbon arrives in the form of free water and/or
water-in-oil emulsions and/or oil-in-water reverse emulsions. The
produced water must go through a series of processing steps to be
useful as boiler feedwater, such as de-oiling, softening and ion
exchange. Typical de-oiler systems include a free water knock out
("FWKO") vessel, followed by a skim tank, induced gas floatation
and finally an oil removal filter. The de-oiler system is
conventionally used at surface to separate the recovered
hydrocarbons from the produced water, and the produced water is
thereafter recycled to the steam generation unit for re-use in
converting same to steam for injection downhole; typically,
however, the produced water contains significant impurities in the
form of inorganic compounds, such as silica, calcium and magnesium
ions, which must be addressed and controlled before the de-oiled
produced water can be introduced to steam generation units as
feedstock.
[0007] Conventional drum boilers operating at circa 2% blowdown
cannot typically be used to generate steam from the produced water
without the use of evaporators to generate high purity feedwater
due to the concentration of impurities such as calcium, silica,
organics and the like that cause precipitation and thereby scaling
and fouling within boiler tubes during the boiling of the water,
which thereby very quickly renders the boiler ineffective in
transferring heat to the water to generate steam and can also
rupture boiler tubes due to the generation of hot spots.
[0008] Alternatively, special types of steam generators are
commonly used, namely so-called "once-through steam generators"
("OTSG" or "OTSGs"), which can better handle higher amounts of
impurities in the produced water feed stream and generate steam
ranging from 65% to 90% steam quality (10-35 parts water containing
the impurities, 65-90 parts steam vapor). Operating at this steam
quality greatly reduces the dissolved salts which foul and scale
the tubes. Nevertheless, produced water pre-conditioning steps are
still necessary, such as the warm lime softening ("WLS") or hot
lime softening ("HLS") process, which injects lime to reduce water
hardness and alkalinity and precipitates silica and carbonate ions
out of the water, and in conjunction with a weak acid cation or
strong acid cation ion exchange ("WACS" or "SACS") process, removes
the calcium and magnesium scale generating ions to acceptable
concentrations, thereby reducing build-up of scale in the OTSG. The
major bulk chemicals used in these processes are lime (Ca(OH)2),
magnesium oxide (MgO), soda ash (Na2CO3), caustic (NaOH), and
hydrochloric acid (HCl). Minor amounts of coagulant and polymer are
used to aid in solid separation.
[0009] The above-mentioned equipment and systems are conventionally
situated in a large, centrally-located facility that can produce
steam for use at various nearby injection wells in the target
reservoir. Some current conventional thermal recovery operations
are accordingly designed based on the concept of a central
processing facility ("CPF") and a plurality of dispersed well pads.
As can be seen in FIG. 1, the CPF-pad arrangement 1 comprises a CPF
2 and well pads 3a, 3b, 3c that are distributed at some appropriate
and functional distance from the CPF 2, and are in communication
with the CPF 2 by means of various pipelines 4 that transport
materials between each well pad 3 and the CPF 2. By distributing
the well pads around and at a distance from the CPF, the idea is
that the reservoir can be exploited with a complex central facility
(the CPF) but relatively simple and easy-to-construct well pads at
various points above the reservoir that can be serviced from the
central facility.
[0010] Each well pad in such a conventional arrangement essentially
functions to inject steam downhole, and to recover produced
materials and pipe them to the CPF for processing. Turning to FIG.
2, the CPF 2 and pad 3 are again seen connected by pipes 4. Such
pipes 4 conventionally include a produced materials pipe 5 for
sending produced materials (generally bitumen, gas, water and
solids) from the pad 3 to the CPF 2 for processing as described
above. Also, the CPF 2 feeds various inputs to the pad 3, such as a
steam supply through a high pressure steam pipe 6. Other inputs may
also need to be supplied from the CPF to the well pad, as is known
to those skilled in the art.
[0011] However, the requirement for the supply of steam from the
CPF to each of the well pads introduces a high-pressure pipeline
environment. That being the case, certain civil structural works
are required, such as above-ground racks and expansion loops for
the pipes. In addition, constructing a very large central facility
in a mega project fashion introduces enhanced costs and execution
risks, both in terms of construction and operation. Smaller and
more modular equipment would facilitate more rapid installation and
execution. Focusing most of the processing equipment in one
relatively large CPF can negatively impact the ability to
effectively exploit the reservoir.
[0012] It would therefore be desirable to have an arrangement that
addresses the issues arising from constructing a large CPF to
process the materials coming from the wells and generating steam
while retaining the benefits of the distributed well pad
system.
BRIEF SUMMARY
[0013] The present invention therefore seeks to provide a novel
CPF-pad arrangement that locates certain equipment and produced
materials treatment at the pads themselves, including the
generation of steam at each pad for injection and thus avoiding the
need for steam piping from the CPF. As the high-pressure steam
pipeline environment is avoided, pipes between the CPF and well
pads will be reduced in number and can be buried.
[0014] According to a first aspect of the present invention there
is provided a method for generating steam for use in a subsurface
hydrocarbon recovery operation, the operation comprising a central
processing facility in fluid communication with at least one well
pad, the well pad for servicing a related hydrocarbon recovery
well, the method comprising the steps of:
locating produced materials treatment means and steam generation
means at the well pad; producing produced materials from the
related hydrocarbon recovery well at the well pad; treating the
produced materials at the well pad to separate water and
hydrocarbon from the produced materials; transporting the
hydrocarbon from the well pad to the central processing facility;
feeding the water to the steam generation means to generate steam;
and injecting the steam into the related hydrocarbon recovery
well.
[0015] In some exemplary embodiments of the first aspect of the
present invention, gas is separated from the produced materials and
treated using gas treatment means located on the well pad, for
example for sulphur removal, before piping the gas for re-use as
fuel.
[0016] In some exemplary embodiments of the first aspect of the
present invention, the hydrocarbon separated from the produced
materials can be subjected to partial upgrading on the well pad
before being transported to the central processing facility, thus
avoiding or reducing the need for diluent to enable pipelining of
the hydrocarbon. Alternatively, the hydrocarbon can be subjected to
partial upgrading at the CPF.
[0017] According to a second aspect of the present invention there
is provided a system for generating steam for use in subsurface
hydrocarbon recovery, the system comprising:
a central processing facility; at least one well pad in fluid
communication with the central processing facility; each well pad
adjacent a related hydrocarbon recovery well(s), the related
hydrocarbon recovery well(s) for producing produced materials;
produced materials treatment means at the well pad for separating
gas, solids, water and hydrocarbon from the produced materials;
pipeline means for transporting the hydrocarbon from the well pad
to the central processing facility; steam generation means at the
well pad for generating steam from the water; and steam injection
means for injecting the steam into the related hydrocarbon recovery
well.
[0018] In some exemplary embodiments of the second aspect of the
present invention, the produced materials treatment means at the
well pad is used for separating water, gas, solids, and hydrocarbon
from the produced materials. The system may further comprise gas
treatment means at the well pad for treating gas separated from the
produced materials, for example for sulphur removal, before piping
the gas for re-use as fuel.
[0019] In some exemplary embodiments of the second aspect of the
present invention, the system further comprises a partial upgrading
plant at the well pad for partially upgrading the hydrocarbon
separated from the produced materials before being transported to
the central processing facility, thus avoiding or reducing the need
for diluent to enable pipelining of the hydrocarbon. Alternatively,
the hydrocarbon can be subjected to partial upgrading at the
CPF.
[0020] A detailed description of exemplary embodiments of the
present invention is given in the following. It is to be
understood, however, that the invention is not to be construed as
being limited to these embodiments.
BRIEF DESCRIPTION OF THE DRAWINGS
[0021] In the accompanying drawings, which illustrate exemplary
embodiments of the present invention:
[0022] FIG. 1 is a simplified view of a conventional prior art
arrangement of a central processing facility and a plurality of
well pads;
[0023] FIG. 2 is a simplified view of conventional piping of
materials between a well pad and a central processing facility;
[0024] FIG. 3 is a simplified schematic view of a first exemplary
system in accordance with the present invention; and
[0025] FIG. 4 is a simplified schematic view of a second exemplary
system in accordance with the present invention.
[0026] Exemplary embodiments of the present invention will now be
described with reference to the accompanying drawings.
DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS
[0027] Turning now to FIGS. 3 and 4, exemplary embodiments of the
present invention are illustrated. The exemplary embodiments are
presented for the purpose of illustrating the principles of the
present invention, and are not intended to be limiting in any
way.
[0028] FIG. 3 illustrates a first exemplary embodiment of the
present invention. A single well pad 10 is illustrated as being in
fluid communication with a CPF (not shown), but it is to be
understood that in most cases a plurality of well pads 10 would be
in communication with a single CPF. The well pad 10 comprises a
separator 12 and a steam generator 14.
[0029] While FIG. 3 shows the separator 12 as a single unit, it
will be clear to those skilled in the art that this would normally
represent a number of discrete cooperating pieces of equipment,
establishing oil removal and water treatment systems. For example,
separator 12 can represent a conventional combination of a FWKO,
skim tanks, induced gas flotation, WLS and WACS units. A
flash-treater could also be employed. Although many different types
of separation technologies could be used with the present invention
as would be clear to those skilled in the art, it is preferred that
the separator 12 comprise compact and modular units such as
hydrocyclones, centrifuges and membrane systems, although the
separator 12 need not be limited to either of these
technologies.
[0030] The function of separator 12 is to take produced material
and separate it into various desired components. The produced
material is normally a mixture of water and hydrocarbon (in an
emulsion), gas and solids, drawn from the well through line 16 to
the separator 12 intake. The separator 12--through whatever process
is inherent in the particular type of separator selected--separates
the produced material into four streams: gas, solids, hydrocarbon
and de-oiled water--the latter intended for use in steam
production. The solids stream passes through line 18 to a landfill
or other storage means familiar to those of skill in the art. The
gas stream can be treated on the well pad 10, for example if it
contains H.sub.2S, and combusted in the steam generator 14.
[0031] The separator 12 also produces a hydrocarbon output 22,
which may be a heavy hydrocarbon such as bitumen. Bitumen is
normally too heavy to transport by pipeline and it is therefore
common to dilute it with a diluent, conventionally a lighter
hydrocarbon, to make it amenable to transport to the CPF for
further processing. As can be seen in the embodiment of FIG. 3, a
diluent 32 is piped in from the CPF or from a diluent line and
injected into the hydrocarbon output line 22 to enable piping to
the CPF; however, the use of diluent can be avoided if hot bitumen
is pipelined, and diluent should therefore be viewed as optional.
Other additives such as drag reduction additives are also known to
those skilled in the art, and may be considered for use with this
exemplary embodiment, and would be added using a line such as the
chemical line 34.
[0032] In addition, chemicals such as a demulsifier may need to be
sourced (from the CPF via pipeline or by tanker) to enable the
desired separation of the produced material. The introduction of
such chemicals is illustrated as line 34 entering the separator
12.
[0033] The final component of the produced material separated by
the separator 12 is the water output 24. As discussed above, there
are existing technologies that can be used to generate water of
sufficient purity to be used as boiler feedstock, and the
particular separation technology must be selected to match the
specification needs of the steam generation technology, which is
within the knowledge of the skilled person. The water output 24
from the separator 12 is then fed into the steam generator 14,
producing steam 26; solids 28 and waste water (or boiler blowdown)
30 would commonly also be produced depending on the steam
generation technology employed. Any solids 28 and waste water 30
would be disposed of in accordance with common knowledge in the
field and applicable laws. The steam 26 is injected back into the
well (not shown) to enable continued production of hydrocarbons as
part of the thermal recovery operation.
[0034] Turning now to FIG. 4, an alternative embodiment of the
present invention is illustrated. While similar in most respects to
the method illustrated in FIG. 3 and as described above, the
alternative embodiment instead seeks to partially upgrade the
separated hydrocarbon stream output from the separator 12. In this
embodiment, the hydrocarbon stream is directed to a partial
upgrading plant ("PUP") 36, in which the hydrocarbon is made
lighter and more amenable to pipeline transport to the CPF. The
partially upgraded hydrocarbon stream 38 is output from the PUP 36
and pipelined to the CPF for further processing. In this
embodiment, then, there is potentially less need for a diluent
stream from the CPF, although some diluent addition as illustrated
in FIG. 3 may still be required. The operation of a PUP is within
the knowledge of the skilled person and will therefore not be
described further herein.
[0035] As can be readily seen, then, there are numerous advantages
provided by the present invention. With the elimination of
high-pressure steam pipes, pipelines can be buried between the CPF
and the well pads, reducing the need for above-ground civil works,
and on-pad steam generation can reduce the risk of steam loss and
the need for pipe insulation. The total area of the CPF itself can
be reduced, possibly by as much as 50% to 75%. Also, as equipment
is sized for a single well pad, project execution costs and risks
can be minimized in many situations.
[0036] The foregoing is considered as illustrative only of the
principles of the invention. Thus, while certain aspects and
embodiments of the invention have been described, these have been
presented by way of example only and are not intended to limit the
scope of the invention. The scope of the claims should not be
limited by the exemplary embodiments set forth in the foregoing,
but should be given the broadest interpretation consistent with the
specification as a whole.
* * * * *