U.S. patent application number 14/113797 was filed with the patent office on 2014-03-27 for methods and systems for providing steam.
This patent application is currently assigned to Hitachi, Ltd.. The applicant listed for this patent is HALLIBURTON ENERGY SERVICES, INC.. Invention is credited to Thomas J. Boone, William C. Carlson, Brian P. Head, Darrel L. Perlau, George R. Scott, Brian C. Speirs.
Application Number | 20140083694 14/113797 |
Document ID | / |
Family ID | 47352191 |
Filed Date | 2014-03-27 |
United States Patent
Application |
20140083694 |
Kind Code |
A1 |
Scott; George R. ; et
al. |
March 27, 2014 |
Methods and Systems for Providing Steam
Abstract
A system is provided for improved steam generation. The system
includes at least two steam systems, wherein a wet steam output
from a first steam system is passed through a first separator. The
first separator configured to separate dry steam from condensate,
and a piping connection is configured to blend the condensate with
a boiler feed water stream at the inlet of a second steam
system.
Inventors: |
Scott; George R.; (Calgary,
CA) ; Head; Brian P.; (Calgary, CA) ; Speirs;
Brian C.; (Calgary, CA) ; Boone; Thomas J.;
(Calgary, CA) ; Perlau; Darrel L.; (Calgary,
CA) ; Carlson; William C.; (Airdrie, CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES, INC. |
Houston |
TX |
US |
|
|
Assignee: |
Hitachi, Ltd.
Chiyoda-ku
JP
|
Family ID: |
47352191 |
Appl. No.: |
14/113797 |
Filed: |
April 4, 2012 |
PCT Filed: |
April 4, 2012 |
PCT NO: |
PCT/US12/32163 |
371 Date: |
October 24, 2013 |
Current U.S.
Class: |
166/272.3 ;
122/1B; 122/451S; 122/489 |
Current CPC
Class: |
F22B 37/26 20130101;
F22B 29/06 20130101; F22D 1/00 20130101; E21B 43/2406 20130101 |
Class at
Publication: |
166/272.3 ;
122/1.B; 122/489; 122/451.S |
International
Class: |
E21B 43/24 20060101
E21B043/24; F22B 37/26 20060101 F22B037/26; F22D 1/00 20060101
F22D001/00; F22B 29/06 20060101 F22B029/06 |
Foreign Application Data
Date |
Code |
Application Number |
Jun 10, 2011 |
CA |
2742563 |
Claims
1. A system for improved steam generation, comprising: at least two
steam systems, wherein a wet steam output from a first steam system
is passed through a first separator; the first separator configured
to separate dry steam from condensate; and a piping connection
configured to supplement a boiler feed water stream with the
condensate at the inlet of a second steam system.
2. The system of claim 1, further comprising a piping connection
configured to dispose of the condensate.
3. The system of claim 2, wherein the amount of condensate
supplementing the boiler feed water stream is changed based, at
least in part, on a demand for dry steam.
4. The system of claim 2, wherein the amount of condensate
supplementing the boiler feed water stream is changed based, at
least in part, on preventing dissolved solids from precipitating in
a steam system.
5. The system of claim 1, wherein a steam system comprises a
once-through steam generator, or a heat recovery steam generator,
or a combination thereof.
6. The system of claim 1, wherein a hydrocarbon development
comprises a cyclic steam stimulation process, a steamflood process,
a steam assisted gravity drainage process, a thermal solvent
process, a sub-surface mining operation, or a surface mining
operation, or any combinations thereof.
7. The system of claim 1, wherein the system is configured to
produce wet steam, dry steam, or a combination thereof.
8. The system of claim 1, comprising: a second separator on the wet
steam output from the second steam system configured to separate
dry steam from condensate; and piping to feed the condensate to an
inlet on a third steam system in a blend with boiler feed
water.
9. The system of claim 1, comprising a plurality of thermal
recovery processes in a hydrocarbon development.
10. The system of claim 9, comprising a first portion of the
plurality of thermal recovery processes configured to use a wet
steam stream and a second portion of the plurality of thermal
recovery processes configured to use a dry steam stream.
11. A method for improving recovery from a hydrocarbon reservoir,
the method comprising: matching a steam quality to a hydrocarbon
development, wherein the steam is generated by a steam generation
facility comprising a plurality of steam systems; and adapting the
steam generation facility to match a change in steam usage caused
by a change in the hydrocarbon development, wherein adapting
comprises: cascading a condensate stream from a separator on an
outlet of at least one steam system to an inlet of another steam
system; and replacing a portion of a boiler feed water stream with
the condensate stream at the inlet, wherein the portion of boiler
feed water replaced is determined by a ratio of dry steam to wet
steam used in the hydrocarbon development.
12. The method of claim 11, comprising performing a plurality of
thermal recovery processes on regions within the hydrocarbon
development, wherein different recovery processes are used for
different regions or at different times.
13. The method of claim 11, comprising performing a solvent
assisted thermal recovery process in the hydrocarbon
development.
14. The method of claim 13, comprising: vaporizing a solvent stream
in a heat exchanger sourcing heat from a wet steam line; and
combining the vaporized solvent stream with dry steam.
15. The method of claim 11, comprising transitioning the steam
generation facility from wet steam to dry steam.
16. The method of claim 11, comprising balancing quantity of
condensate reused with the quality of the steam generated to keep
dissolved solids from precipitating in a steam system.
17. The method of claim 11, comprising sequentially converting a
plurality of steam systems from wet steam service to dry steam
service to match a change in the steam quality used in the
hydrocarbon development.
18. The method of claim 17, comprising reverting a portion of the
plurality of steam systems to wet steam service to match a change
in the steam quality used in the hydrocarbon development.
19. The method of claim 17, comprising adjusting the steam quality
at the exit of each of the plurality of steam systems to ensure
that contaminants present in a boiler feed water remain soluble in
the steam system.
20. The method of claim 17, comprising adding a steam system to the
plurality of steam systems to utilize surplus boiler feed water
freed when converting a steam system from wet steam service to dry
steam service.
21. The method of claim 17, comprising shutting-in steam systems as
a result of a reduction in boiler feed water resulting from a
conversion of a portion of the steam systems from wet steam service
to dry steam service.
22. The method of claim 11, comprising: drilling a plurality of
infill steam injection wells between each of a plurality of steam
assisted gravity drainage (SAGD) wellpairs; injecting dry steam
into a plurality of steam injection wells in the plurality of SAGD
wellpairs; and injecting wet steam into the plurality of infill
steam injection wells.
23. The method of claim 11, comprising: injecting dry steam into a
plurality of steam injection wells in a plurality of steam assisted
gravity drainage (SAGD) wellpairs; and injecting wet steam into a
plurality of steamflood wells.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority to Canadian Patent
Application 2,742,563 filed Jun. 10, 2011 entitled, METHODS AND
SYSTEMS FOR PROVIDING STEAM; the entirety of which is incorporated
by reference herein.
FIELD
[0002] The present techniques provide methods for generating steam.
More specifically, the techniques provide methods and systems for
adapting steam generation to hydrocarbon recovery processes.
BACKGROUND
[0003] This section is intended to introduce various aspects of the
art, which may be associated with exemplary embodiments of the
present techniques. This discussion is believed to assist in
providing a framework to facilitate a better understanding of
particular aspects of the present techniques. Accordingly, it
should be understood that this section should be read in this
light, and not necessarily as admissions of prior art.
[0004] Modern society is greatly dependent on the use of
hydrocarbons for fuels and chemical feedstocks. Hydrocarbons are
often found in subsurface rock formations that can be termed
"reservoirs." Removing hydrocarbons from the reservoirs depends on
numerous physical properties of the rock formations, such as the
permeability of the rock containing the hydrocarbons, the ability
of the hydrocarbons to flow through the rock formations, and the
proportion of hydrocarbons present, among others.
[0005] Easily harvested sources of hydrocarbon are dwindling,
leaving less accessible sources to satisfy future energy needs.
However, as the costs of hydrocarbons increase, these less
accessible sources become more economically attractive. For
example, the harvesting of oil sands to remove hydrocarbons has
become more extensive as it has become more economical. The
hydrocarbons harvested from these reservoirs may have relatively
high viscosities, for example, ranging from 8 API, or lower, up to
20 API, or higher. Accordingly, the hydrocarbons may include heavy
oils, bitumen, or other carbonaceous materials, collectively
referred to herein as "heavy oil," which are difficult to recover
using standard techniques.
[0006] Several methods have been developed to remove hydrocarbons
from oil sands. For example, strip or surface mining may be
performed to access the oil sands, which can then be treated with
hot water or steam to extract the oil. However, deeper formations
may not be accessible using a strip mining approach. For these
formations, a well can be drilled to the reservoir and steam, hot
air, solvents, or combinations thereof, can be injected to lower
the viscosity of the hydrocarbons. The reduced viscosity
hydrocarbons may then be collected by the injection well or by
other wells and brought to the surface.
[0007] A number of techniques have been developed for harvesting
heavy oil from subsurface formations using thermal recovery
techniques. Thermal recovery operations are used around the world
to recover liquid hydrocarbons from both sandstone and carbonate
reservoirs. These operations include a suite of steam based in situ
thermal recovery techniques, such as cyclic steam stimulation
(CSS), steamflooding and steam assisted gravity drainage (SAGD) as
well as surface mining and their associated thermal based surface
extraction techniques.
[0008] For example, CSS techniques include a number of enhanced
recovery methods for harvesting heavy oil from formations that use
steam heat to lower the viscosity of the heavy oil. In one
embodiment, the CSS process raises the steam injection pressure
above the formation fracturing pressure to create fractures within
the formation and enhance the surface area access of the steam to
the heavy oil. The steam raises the temperature of the heavy oil
during a heat soak phase, lowering the viscosity of the heavy oil.
The injection well may then be used to produce heavy oil from the
formation. The cycle is often repeated until the cost of injecting
steam becomes uneconomical, for instance if the cost is higher than
the money made from producing the heavy oil. However, successive
steam injection cycles may reenter earlier created fractures and,
thus, the process becomes less efficient over time.
[0009] Solvents may be used in combination with steam in CSS
processes, such as in mixtures with the steam or in alternate
injections between steam injections. After injection with the
steam, the liquid hydrocarbons are transported as vapors to contact
heavy oil surrounding steamed areas between adjacent wells. The
injected hydrocarbons can be produced as a mixture with the heavy
oil phase. The loading of the liquid hydrocarbons injected with the
steam can be chosen based on pressure drawdown and fluid removal
from the reservoir using lift equipment in place for the CSS.
[0010] Another group of techniques is based on a continuous
injection of steam through a first well to lower the viscosity of
heavy oils and a continuous production of the heavy oil from a
lower-lying second well. Such techniques may be termed "steam
assisted gravity drainage" or SAGD. In SAGD, two horizontal wells
are completed into the reservoir. These wells can be started as
slant wells at surface or vertical wells and drilled to different
depths within the reservoir. Thereafter, using directional drilling
technology, the two wells are extended in the horizontal direction
that result in two horizontal wells, vertically spaced from, but
otherwise vertically aligned with the other. Ideally, the
production well is located above the base of the reservoir but as
close as practical to the bottom of the reservoir, and the
injection well is located vertically 10 to 30 feet (3 to 10 meters)
above the horizontal well used for production.
[0011] The upper horizontal well is utilized as an injection well
and is supplied with steam from the surface. The steam rises from
the injection well, permeating the reservoir to form a vapor
chamber that grows over time towards the top of the reservoir. The
steam, and its condensate, raise the temperature of the reservoir
and consequently reduce the viscosity of the heavy oil in the
reservoir. The heavy oil and condensed steam will then drain
downward through the reservoir under the action of gravity and may
flow into the lower production well, whereby these liquids can be
pumped to the surface. At the surface, the condensed steam and
heavy oil are separated, and the heavy oil may be diluted with
appropriate light hydrocarbons for transport by pipeline.
[0012] As a result of the unique wellbore configuration in SAGD,
any condensate, e.g., any liquid water phase, injected into the
reservoir with the steam will fall directly to the underlying
production well due to the influence of gravity, and thereby not
contribute to the recovery of the hydrocarbons. For this reason,
the current convention in SAGD projects is to separate the
condensate from a wet steam flow and inject the dry steam phase
into the injection wells used in the recovery process. As used
herein, wet steam is a flow of steam that holds entrained water
droplets originating either from incomplete conversion of a water
stream into steam or from condensation of the steam. The steam
after the condensate has been removed is referred to as dry
steam.
[0013] As discussed above, SAGD is a process where the recovery
process benefits from the injection of dry steam. In contrast, CSS,
steamflooding and SAGD infill well injectors are examples of
processes that make thermally efficient use of wet steam which can
also be demonstrated using numerical simulation.
[0014] The vast majority of the commercial thermal recovery schemes
produce steam for injection activities through
once-through-steam-generators (OTSG) or cogeneration facilities
that utilize heat-recovery-steam-generators (HRSG). A common
feature of OTSGs and HRSGs is that the steam is generated inside a
series of boiler tubes that are heated by combustion of a
hydrocarbon fuel external to the boiler tubes. As a result of the
application of this external heat source a progressively larger
fraction of the water inside the boiler tubes is converted to steam
at it passes through the steam generator. The quality of the steam
is measured as the percentage of vapor by mass of cold water. Thus,
an 80% quality steam is a steam flow containing 80% of its mass in
vapor.
[0015] Due to the presence of contaminants, such as hardness,
salts, and silica, the maximum steam quality generated in OTSG and
HRSG generators is typically between 60 to 80%. This means that 20
to 40% of the water mass entering the steam generator remains as
water at the exit of the steam generator. Feed water used for
generating steam in OTSGs and HRSGs can come from many sources and,
depending upon the properties of the raw water, is treated to
remove contaminants and render it suitable as a feed stream for a
OTSG or HRSG.
[0016] In these styles of generators the maximum steam quality can
be limited by the need to ensure that a continuous film of water
coats the inner wall of boiler tube surfaces. If the continuous
water film is not present, local dry spots will be created, leading
to elevated tube temperatures and potential tube overheating. Also,
by converting 100% of the water to steam in these areas,
contaminants present in the water entering the steam generator can
be deposited on the boiler tubes in the form of scale. These
deposits impede heat transfer and further contribute to tube
overheating. Significant tube overheating can result in the failure
of the boiler tube. Limiting the steam quality may ensure that
sufficient water remains in the generator to ensure that the
contaminants exceed their solubility limit, limiting the potential
for scaling.
[0017] In conventional thermal extraction processes, such as
steamfloods, SAGD, CSS projects, steam injection infill wells for
CSS and SAGD, and sub-surface and surface mining using surface
extraction, the recovery processes are able to effectively utilize
a significant fraction of the heat contained within the condensate
phase that is either injected into the reservoir or blended with
the mined ore. For this reason, wet steam is sufficient for the
recovery process.
[0018] Where the in situ recovery process being utilized can
effectively utilize the heat contained in the condensate, the wet
steam generated in the OTSG or HRSG is transported using pipelines
to the wells and injected via wellbores into the hydrocarbon
bearing reservoir. The injected steam heats the hydrocarbon,
reducing its viscosity and allowing it to be recovered via either
the same wells the steam was injected into or via one or more
laterally and/or vertically offset production wells. In a surface
mining and associated thermal based surface extraction technique
the wet steam is used to heat the mined ore to allow its efficient
extraction from the reservoir fabric.
[0019] The fluids produced as a result of the thermal recovery
process contain liquid hydrocarbons recovered from the reservoir,
water from condensed steam, formation water, and various minerals
and other constituents which may be dissolved or suspended in the
mixture, along with steam and gaseous constituents. The produced
fluids are typically transported to a centralized facility and
separated, forming vapor, liquid hydrocarbon, and aqueous streams.
An aqueous stream, which has as its major component produced water
used for in situ recovery processes, can be treated to render it
suitable for re-use as boiler feed water in the OTSG or HRSG. This
treatment can include the removal of the majority of the hardness
and a reduction in both iron and silica levels.
[0020] Where the recovery process being utilized cannot effectively
utilize the heat contained in the condensate, the wet steam
generated in the OTSG or HRSG is separated into vapor and
condensate streams downstream of the generator exit. The resulting
dry steam is then transported to the wells via pipeline, while the
condensate stream contains essentially all of the impurities that
were present in the boiler feed water, in addition to a significant
quantity of heat.
[0021] As previously noted, the condensate stream can represent
between 20 and 40% of the boiler feed water stream, depending on
the quality of the steam generated. Managing the condensate can be
problematic. If sufficient make-up water capacity and disposal
capacity is required, the facility can be designed to maximize the
heat recovery from the condensate before disposing of it. If
make-up water capacity or disposal capacity is limited, then
emphasis is placed on recycling the condensate.
[0022] One common practice is to recycle a portion of the
condensate, with or without processing in a water treatment plant,
and reusing it as boiler feed water. However, the quantity of
condensate that can be recycled is limited by the build-up of
dissolved solids in the boiler feed water, which can precipitate in
the boiler tubes if a portion of the condensate is not continuously
purged from the system. If the development is currently using two
recovery processes, one using dry steam and the second using wet
steam, a second practice may take the condensate and blend it with
the wet steam being utilized in the second recovery process. This
can be an acceptable practice as long as the dry steam demand is
small compared to the wet steam needs.
[0023] Various techniques have been developed to improve the
quality of a condensate that is to be used as boiler feed water.
For example, U.S. Pat. No. 7,591,309 to Minnich, et al., discloses
an evaporation process for conversion of condensate into a high
quality water stream and either a brine or a solids reject stream
suitable for disposal. In the method, de-oiled produced water is
processed through an evaporator at high pH and high pressure. The
evaporator is driven by a commercial boiler. The steam from the
evaporator can be used in SAGD. The evaporator blowdown, or
condensate, may be further treated in a crystallizing evaporator to
provide a zero liquid discharge (ZLD) system. With most produced
waters, at least 98% of the incoming produced water stream can be
recovered in the form of high pressure steam.
[0024] U.S. Patent Application Publication No. 2009/0133643 by
Suggett, et al., discloses a method and apparatus for generating
steam while reducing the quantity of boiler blowdown and, thus,
increasing the amount of feed water that is re-used or re-cycled in
generating the steam. The application claims that, on a sustained
basis, the blowdown stream at the outlet of a once-through steam
generator can be routed to the inlet of a second once-through steam
generator that is in series with the first, that blowdown stream
can be used to generate additional steam in the second once-through
steam generator and further reduce the amount of blowdown, and that
this can be accomplished without need of any treatment that reduces
hardness or silica levels of the blowdown stream prior to its
entering or during its entry into the inlet of the second
once-through steam generator. The output of this second steam
generator is a substantially dry saturated steam vapor stream and,
a blowdown stream whose mass rate has been reduced substantially
from that of the blowdown stream exiting the first steam
generator.
[0025] Similarly, Canadian Patent No. 2,621,991 to Speirs, et al.,
teaches a separate OTSG (or HRSG), referred to as a boiler blowdown
OTSG, which is located in series with one or more other OTSGs (or
HRSGs) and can utilize the condensate from the initial OTSGs (or
HRSGs) to generate wet steam. Reuse of the condensate in this way
results in a significant reduction in the size of the condensate
stream and an increase in the effective steam quality being
generated. In the process boiler feed water (BFW) of sufficient
quality is fed through one or more primary wet steam generators to
generate primary wet steam. The primary wet steam is separated into
primary dry steam and a primary liquid phase. The primary liquid
phase can be fed into one or more secondary steam generators to
generate secondary steam. The secondary steam generators may or may
not be wet steam generators.
[0026] During the transition from a recovery process that is able
to effectively utilize wet steam to a recovery process requiring
dry steam the amount of condensate that is reused may need to be
changed. The current approaches to increase the reuse of condensate
generally have a number of problems. For example, many developments
have a much larger requirement for wet steam than dry steam.
Changing the reuse of the condensate may lose the benefits of the
heat contained in the condensate. New water treatment technology
may be needed in the operation. A series of boiler blowdown steam
generators may be needed in order to match the volume of condensate
not being utilized in the dry steam scheme. Further, a large
fraction of the installed steam generation capacity may need to be
converted to dry steam production in order to allow one of the
existing steam generators to be used as a dedicated in series
boiler blowdown steam generator.
[0027] As the techniques used to recover resource from a reservoir
are adapted to the remaining resource present, the amounts and
quality of the steam needed by the development may change. However,
none of the references described above disclose tailoring the steam
sources or quality to the changing needs of the reservoir over
time.
SUMMARY
[0028] An embodiment of the present techniques provides a system
for improved steam generation. The system includes at least two
steam systems, wherein a wet steam output from a first steam system
is passed through a first separator. The first separator is
configured to separate dry steam from condensate and a piping
connection is configured to supplement a boiler feed water stream
with the condensate at the inlet of a second steam system. The
amount of condensate supplementing the boiler feed water stream is
changed based, at least in part, on a demand for dry steam or on
the water quality of the condensate.
[0029] Another embodiment provides a method for improving recovery
from a hydrocarbon reservoir. The method includes matching a steam
quality to a hydrocarbon development, wherein the steam is
generated by a steam generation facility comprising a plurality of
steam systems. The steam generation facility is adapted to match a
change in steam usage caused by a change in the hydrocarbon
development, by cascading a condensate stream from a separator on
an outlet of at least one steam system to an inlet of another steam
system and replacing a portion of boiler feed water stream with the
condensate stream at the inlet. The portion of boiler feed water
replaced is determined by a ratio of dry steam to wet steam used in
the hydrocarbon development.
DESCRIPTION OF THE DRAWINGS
[0030] The advantages of the present techniques are better
understood by referring to the following detailed description and
the attached drawings, in which:
[0031] FIG. 1 is a drawing of a development illustrating the use of
both a surface mining recovery process and a steam assisted gravity
drainage (SAGD) recovery process to harvest hydrocarbons from a
reservoir;
[0032] FIG. 2 is a drawing of a conventional steam generation
system that may be utilized to generate steam for thermal or
thermal-solvent recovery processes, such as CSS;
[0033] FIG. 3 is a drawing of a steam generation system that uses
three steam generators in parallel to generate wet steam for a
thermal recovery process;
[0034] FIG. 4 shows a steam generation system that can be utilized
to generate dry steam for thermal recovery processes such as SAGD
developments;
[0035] FIG. 5 is a drawing of a steam generation system in a series
design in which the condensate from a first steam generator is
separated from the dry steam in a separator and used as a feed
water stream for a smaller steam generator;
[0036] FIG. 6 is a drawing of a steam generation system using
multiple steam generators for the purpose of generating primarily
dry steam;
[0037] FIG. 7 is a drawing of a steam generation system after
conversion of one steam generator to the production of dry
steam;
[0038] FIG. 8 is a drawing of a steam generation system after
conversion of two steam generators to the production of dry
steam;
[0039] FIG. 9 is a drawing of a steam generation system that may
provide similar production of wet and dry steam as described for
FIGS. 7 and 8;
[0040] FIG. 10 is a drawing of a steam generation system that may
not provide material steam quality improvement, but may provide
significant operating flexibility;
[0041] FIG. 11 is a drawing of the system of FIGS. 7 and 8 after
the third steam system is converted to dry steam service;
[0042] FIG. 12 is a drawing of a steam generation system in which
three steam systems operate in parallel and generate dry steam by
cascading the condensate sequentially to the inlet of the adjacent
steam system;
[0043] FIG. 13 is a drawing of a steam generation system showing
that the cascading process may be applied to steam systems having
multiple steam generators operating in parallel;
[0044] FIG. 14 is a drawing of a steam generation system that
includes a seventh steam generator installed in a fourth steam
system;
[0045] FIG. 15 is a drawing of a steam generator that is modified
to increases both throughput and dry steam production; and
[0046] FIG. 16 is a process flow diagram of a method for tailoring
the quality of steam production to field needs;
[0047] FIG. 17 is a drawing of a development for which dry steam is
separated from the wet steam and the different steam lines are
directed to regions of the field where recovery processes
efficiently use the wet or dry steam;
[0048] FIG. 18 is a diagram of a SAGD process with infill wells
where the efficiency of the process is enhanced by directing dry
steam to the SAGD injection wells 1804 and wet steam to the infill
well injectors; and
[0049] FIG. 19 is another diagram of a SAGD process with infill
wells where the efficiency of the process is enhanced by directing
dry steam to the SAGD injection wells 1906 and wet steam to the
infill well injectors.
DETAILED DESCRIPTION
[0050] In the following detailed description section, specific
embodiments of the present techniques are described. However, to
the extent that the following description is specific to a
particular embodiment or a particular use of the present
techniques, this is intended to be for exemplary purposes only and
simply provides a description of the exemplary embodiments.
Accordingly, the techniques are not limited to the specific
embodiments described below, but rather, include all alternatives,
modifications, and equivalents falling within the true spirit and
scope of the appended claims.
[0051] At the outset, for ease of reference, certain terms used in
this application and their meanings as used in this context are set
forth. To the extent a term used herein is not defined below, it
should be given the broadest definition persons in the pertinent
art have given that term as reflected in at least one printed
publication or issued patent. Further, the present techniques are
not limited by the usage of the terms shown below, as all
equivalents, synonyms, new developments, and terms or techniques
that serve the same or a similar purpose are considered to be
within the scope of the present claims.
[0052] As used herein, "bitumen" is a naturally occurring heavy oil
material. It is often the hydrocarbon component found in oil sands.
Bitumen can vary in composition depending upon the degree of loss
of more volatile components. It can vary from a very viscous,
tar-like, semi-solid material to solid forms. The hydrocarbon types
found in bitumen can include aliphatics, aromatics, resins, and
asphaltenes. A typical bitumen might be composed of:
[0053] 19 wt. % aliphatics, which can range from 5 wt. %-30 wt. %,
or higher;
[0054] 19 wt. % asphaltenes, which can range from 5 wt. %-30 wt. %,
or higher;
[0055] 30 wt. % aromatics, which can range from 15 wt. %-50 wt. %,
or higher;
[0056] 32 wt. % resins, which can range from 15 wt. %-50 wt. %, or
higher; and
[0057] some amount of sulfur, which can range in excess of 7 wt.
%.
In addition bitumen can contain some water and nitrogen compounds
ranging from less than 0.4 wt. % to in excess of 0.7 wt. %. The
metals content, while small, can be removed to avoid contamination
of the product synthetic crude oil (SCO). Nickel can vary from less
than 75 ppm (part per million) to more than 200 ppm. Vanadium can
range from less than 200 ppm to more than 500 ppm. The percentage
of the hydrocarbon types found in bitumen can vary.
[0058] As used herein, "condensate" includes liquid water formed by
the condensation of steam. Steam may also entrain liquid water, in
the form of water droplets. This entrained water may also be termed
condensate, as it may arise from condensation of the steam,
although the entrained water droplets may also originate from the
incomplete conversion of liquid water to steam in a boiler.
[0059] As used herein, a "development" is a project for the
recovery of hydrocarbons using integrated surface facilities and
long term planning. The development can be directed to a single
hydrocarbon reservoir, although multiple proximate reservoirs may
be included.
[0060] As used herein, "exemplary" means "serving as an example,
instance, or illustration." Any embodiment described herein as
"exemplary" is not to be construed as preferred or advantageous
over other embodiments.
[0061] As used herein, "facility" as used in this description is a
collection of physical equipment through which hydrocarbons and
other fluids may be either produced from a reservoir or injected
into a reservoir. A facility may also include equipment which can
be used to control production or completion operations. In its
broadest sense, the term facility is applied to any equipment that
may be present along the flow path between a reservoir and its
delivery outlets. Facilities may comprise production wells,
injection wells, well tubulars, wellhead equipment, gathering
lines, manifolds, pumps, compressors, separators, surface flow
lines, steam generation plants, extraction plants, processing
plants, water treatment plants, and delivery outlets. In some
instances, the term "surface facility" is used to distinguish those
facilities other than wells.
[0062] As used herein, a "heat recovery steam generator" or HRSG is
a heat exchanger or boiler that recovers heat from a hot gas
stream. It produces steam that can be used in a process or used to
drive a steam turbine. A common application for an HRSG is in a
combined-cycle power plant, where hot exhaust from a gas turbine is
fed to the HRSG to generate steam which in turn drives a steam
turbine. As described herein, the HRSG may be used to provide steam
to an enhanced oil recovery process, such as CSS or SAGD.
[0063] As used herein, "heavy oil" includes oils which are
classified by the American Petroleum Institute (API), as heavy oils
or extra heavy oils. In general, a heavy oil has an API gravity
between 22.3.degree. (density of 920 kg/m3 or 0.920 g/cm3) and
10.0.degree. (density of 1,000 kg/m3 or 1 g/cm3). An extra heavy
oil, in general, has an API gravity of less than 10.0.degree.
(density greater than 1,000 kg/m3 or greater than 1 g/cm3). For
example, a source of heavy oil includes oil sand or bituminous
sand, which is a combination of clay, sand, water, and bitumen. The
thermal recovery of heavy oils is based on the viscosity decrease
of fluids with increasing temperature or solvent concentration.
Once the viscosity is reduced, the mobilization of fluids by steam,
hot water flooding, or gravity is possible. The reduced viscosity
makes the drainage quicker and therefore directly contributes to
the recovery rate.
[0064] As used herein, a "hydrocarbon" is an organic compound that
primarily includes the elements hydrogen and carbon, although
nitrogen, sulfur, oxygen, metals, or any number of other elements
may be present in small amounts. As used herein, hydrocarbons are
used to refer to components found in bitumen, or other oil
sands.
[0065] As used herein, a "reservoir" is a subsurface rock or sand
formation from which a production fluid can be harvested. The rock
formation may include sand, granite, silica, carbonates, clays, and
organic matter, such as oil, gas, or coal, among others. Reservoirs
can vary in thickness from less than one foot (0.3048 m) to
hundreds of feet (hundreds of m).
[0066] As used herein, and discussed in detail above, "Steam
Assisted Gravity Drainage" (SAGD), is a thermal recovery process in
which steam is injected into a first well to lower a viscosity of a
heavy oil, and fluids are recovered from a second well. Both wells
are usually horizontal in the formation and the first well lies
above the second well. Accordingly, the reduced viscosity heavy oil
flows down to the second well under the force of gravity, although
pressure differential may provide some driving force in various
applications.
[0067] As used herein, a "steam generator" may include any number
of devices used to generate steam for a process facility, either
directly or as part of another process. Steam generators may
include, for example, heat recovery steam generators (HRSG), and
once through steam generators (OTSG), among others. The steam may
be generated at a number of quality levels. Steam quality is
measured by the mass fraction of a cold water stream that is
converted into a vapor. For example, an 80% quality steam has
around 80 wt. % of the feed water converted to vapor. The steam is
generated as wet steam that contains both steam vapor and
associated condensate (or water). The wet steam may be passed
through a separator to generate a dry steam, i.e., without
entrained condensate. As a result of the separation, the separator
also generates a liquid condensate stream.
[0068] As used herein, a "steam system" includes one or more steam
generators running in parallel from a common feed water source and
feeding steam to a common outlet. The steam system may include any
number or types of steam generators in parallel. Often, the
parallel steam generators of the steam system generate steam at a
similar quality level.
[0069] As used herein, "substantial" when used in reference to a
quantity or amount of a material, or a specific characteristic
thereof, refers to an amount that is sufficient to provide an
effect that the material or characteristic was intended to provide.
The exact degree of deviation allowable may in some cases depend on
the specific context.
[0070] As used herein, "thermal recovery processes" include any
type of hydrocarbon recovery process that uses a heat source to
enhance the recovery, for example, by lowering the viscosity of a
hydrocarbon. These processes may be based on heated water, wet
steam, or dry steam, alone, or in any combinations. Further, any of
these components may be combined with solvents to enhance the
recovery. Such processes may include subsurface processes, such as
cyclic steam stimulation (CSS), steamflooding, and SAGD, among
others, and processes that use surface processing for the recovery,
such as sub-surface mining and surface mining.
[0071] As used herein, a "wellbore" is a hole in the subsurface
made by drilling or inserting a conduit into the subsurface. A
wellbore may have a substantially circular cross section or any
other cross-sectional shape, such as an oval, a square, a
rectangle, a triangle, or other regular or irregular shapes. As
used herein, the term "well," when referring to an opening in the
formation, may be used interchangeably with the term "wellbore."
Further, multiple pipes may be inserted into a single wellbore, for
example, to limit frictional forces in any one pipe.
Overview
[0072] The thermal recovery processes chosen for a particular stage
of a development sets the steam quality to be utilized. For
example, in the early cycles of a recovery process such as cyclic
steam stimulation (CSS) wet steam is sufficient, since the majority
of recovery mechanisms are not related to gravity drainage, but may
include dilation/compaction, solution gas drive, water flashing,
and the like. As the CSS recovery process matures, the significance
of these additional recovery mechanisms declines and the recovery
role of gravity drainage increases. Similarly, conventional
steamflood processes for hydrocarbon recovery may use a combination
of heating and the imposition of a significant pressure gradient to
displace the oil to the offset production wells, allowing the use
of wet steam. However, once a significant aqueous or vapor
saturation connects the injection wells to the production wells, it
may no longer be possible to impose a pressure gradient, and
gravity drainage will become dominant recovery mechanism. As
gravity drainage becomes more important, it becomes more efficient
to use higher quality steam or even dry steam.
[0073] In addition to different stages of the recovery, different
recovery processes may be used in a single development. For
example, in shallow hydrocarbon deposits certain areas of the
deposit may be reached with surface mining and extraction
techniques, while other areas can be harvested with in situ
recovery techniques. Different types of techniques may utilize
different balances of steam or water quality.
[0074] Embodiments described herein provide steam generation
designs and methods for transitioning from a recovery process that
utilizes wet steam to a recovery process that utilizes dry steam,
or vice-versa. The systems and methods may reduce facility costs
and make-up water requirements when generating steam in
developments that use thermal recovery processes requiring dry
steam. In some embodiments, the condensate stream may be cascaded
between steam generators. In these embodiments, the residual
condensate can be blended with the boiler feed water being fed to
an adjacent steam system in such a way that the dissolved
contaminants do not compromise steam generator function. As used
here, "cascading" indicates that the items are connected
successively end to start to form a single path.
[0075] FIG. 1 is a drawing of a development 100 illustrating the
use of both a surface mining 102 recovery process and a steam
assisted gravity drainage (SAGD) 104 recovery process to harvest
hydrocarbons 106 from a reservoir 108. It will be clear that the
techniques described herein are not limited to this combination, or
these specific techniques, as any number of techniques or
combinations of techniques may be used in embodiments described
herein. The surface mining 102 may be used to reach a portion of
the reservoir 108 that is closer to the surface, while the SAGD 104
recovery may be used to access hydrocarbons in a portion of the
reservoir 108 that is at a greater depth. In the development 100, a
steam generation facility 109 is used to generate steam 110, which
can be provided to surface separation facility 112 and an injection
facility 114. The steam 110 may include both wet steam and dry
stream, for example, carried in different pipes from the steam
generation facility 109.
[0076] The surface mining 102 uses heavy equipment 116 to remove
hydrocarbon containing materials 118, such as oil sands, from the
reservoir 108. The hydrocarbon containing materials are offloaded
at the separation facility 112, where a thermal process, such as a
Clark hot water extraction (CHWE), among others, may be used to
separate a hydrocarbon stream 120 from a tailings stream 122. The
tailings stream 122 may be sent to a tailings pond 124, or may be
injected into a sub-surface formation for disposal. A water stream
126 may be recycled to the steam generation facility 109. The
extraction process may utilize wet steam from the steam generation
facility 108.
[0077] The SAGD 104 process injects the steam 110 through injection
wells 128 to harvest hydrocarbons by raising the temperature of a
portion 130 of the reservoir 108 to lower the viscosity of the
hydrocarbons 131, allowing the hydrocarbons 131 to flow to
collection wells 132. Although, for the sake of clarity, the
injection wells 128 and collection wells 132 are shown as
originating from different locations in FIG. 1, these wells 128 and
132 may be drilled from the same surface pads to enable easier
tracking between the wells 128 and 132. The resulting streams 134
from the reservoir 108 may include the hydrocarbons 131 and the
condensate from the steam 110. The streams 134 can be processed at
a surface facility 136 to remove at least some of the water. The
SAGD process 104 may utilize higher quality or dry steam from the
steam generation facility 109.
[0078] The hydrocarbon stream 138 and water stream 140 from the
SAGD process 104 may be sent to a transportation facility 142,
which may provide further separation and purification of the
incoming streams 120, 138, and 140, prior to sending the marketable
hydrocarbons 106 on to further processing facilities. The resulting
process water 144 can be returned to the steam generation facility
109 for recycling.
[0079] FIG. 2 is a drawing of a conventional steam generation
system 200 that may be utilized to generate steam for thermal or
thermal-solvent recovery processes, such as CSS. In this figure, a
feed water stream 202 is treated in a water treatment facility 204
to reduce the concentration of contaminants that may cause scale to
be deposited in the steam generator 206.
[0080] The water treatment facility 204 may use a number of
techniques to reduce the contaminants in the feed water stream 202,
including, for example, hot lime softening which may lower the
concentration of contaminates by forcing their precipitation. Any
number of other techniques may also be used alone or in various
combinations, including evaporative purification (distillation),
membrane purification, chemical purification, ion exchange, and the
like.
[0081] The treated water provides a boiler feed water 205 that can
be used by a steam generator 206 to generate wet steam 208. The wet
steam 208 can be transported via pipeline to a development where is
it injected into a reservoir using wells. The steam generator 206
may be any type of steam generator, for example, a once-through
steam generator (OTSG), a heat-recovery steam generator (HRSG), and
the like. Further, the steam generation system 200 is not limited
to a single steam generator 206, but may include any number of
steam generators 206 in parallel.
[0082] FIG. 3 is a drawing of a steam generation system 300 that
uses three steam generators 206 in parallel to generate wet steam
for a thermal recovery process. Like numbered items are as
described in the figures above. As noted above, a steam generation
system 300 may include a number of parallel steam generators 206,
which may be any combinations of OTSG or HRSG units. Each steam
generator 206 is supplied with boiler feed water 205 from the water
treatment facility 204. The resulting wet steam flow 208 from each
steam generator 206 can be combined to form a single wet steam
stream 302 that may be transported to the injection wells or used
in surface facilities. The steam generation systems 200 and 300,
discussed with respect to FIGS. 2 and 3, may be adapted to provide
dry steam as discussed with respect to FIG. 4.
[0083] FIG. 4 shows a steam generation system 400 that can be
utilized to generate dry steam 402 for thermal recovery processes
such as SAGD developments. Like numbered items are as described in
the figures above. Once the wet steam 208 exits the steam generator
206 it is sent to a separator 404, which separates the two phases.
The vapor phase or dry steam 402 leaves the separator 404 and may
then be transported via pipeline to the development where is it
injected into a reservoir using wells, for example, as discussed
with respect to FIG. 1.
[0084] The liquid phase or condensate 406 can be sent to disposal
408, such as injection into a waste well. A portion 410 of the
condensate 406 can be recycled to the inlet 412 of the steam
generator 206. Typically, less than 100% of the condensate 406 will
be recycled, as any dissolved salts in the condensate 406 will be
concentrated over time and can foul the boiler tubes in the steam
generator 206. Therefore, when recycling the condensate 406, at
least a portion is continuously purged to disposal 408 and replaced
by clean boiler feed water 205.
[0085] Although not shown in FIG. 4, the condensate 406 that is
purged from the system can go through additional processing to
recover heat, for example, through the use of heat exchange
devices. Further, high quality make-up water may be obtained from
the condensate 406, for example, by processing the condensate 406
in the water treatment facility 204. For example, this may be
performed by flashing the stream to a lower pressure and condensing
the steam stream that results from that pressure change, among
other techniques.
[0086] FIG. 5 is a drawing of a steam generation system 500 in a
series design in which the condensate 406 from a first steam
generator 206 is separated from the dry steam 402 in a separator
404 and used as a feed water stream for a smaller steam generator
502. Like numbered items are as described in the figures above. The
wet steam 504 generated by the smaller steam generator 502 can be
passed through a second separator 506. The dry steam 508 from the
second separator 506 can be combined with the dry steam 402 from
the first separator 404 to form a combined dry steam 510, which may
be transported to injection wells by a pipeline. The condensate 512
from the second separator 506 may be sent to disposal 408, such as
a disposal well or pond. A portion of the condensate 512, or even
all, may be returned to the water treatment facility 204 to
separate impurities and recover the water.
[0087] The smaller steam generator 502 may be termed a "blowdown"
steam generator. If contaminants in the condensate 406 are
sufficiently below their saturation levels, the use of the two
steam generators 206 and 502 in series allows the steam quality to
be increased, as measured per unit of boiler feed water 205
utilized.
[0088] FIG. 6 is a drawing of a blowdown steam generation system
600 using similarly sized steam generators 206 and 602. Like
numbered items are as described in the figures above. In the
blowdown steam-generation system 600, the number of parallel steam
generators 206 used to supply a single blowdown steam generator 602
is 1/(1-the generated steam quality). Thus, if the desired steam
quality is 80%, five parallel steam generators 206 are used ahead
of each blowdown steam generator 602, as is represented in FIG. 6.
This configuration will often generate a very large quantity of
steam and, therefore, may be relevant for large projects.
Tailoring Steam Generation for Project Development
[0089] In an embodiment, steam production may be tailored to fit
the current needs of the development. This may allow conversion of
particular steam generation systems from producing only wet steam
to producing a combination of wet and dry steam, or only dry steam.
Further, as the development process continues, the proportion of
dry steam generated may be increased.
[0090] Although embodiments are not limited to the following
conditions, for the purposes of this explanation, it is assumed
that an existing commercial development starts by using 100% of the
steam capacity to support a CSS development using wet steam. As the
development matures, a steamflood based follow-up process is
implemented, resulting in 67% of the steam capacity being used to
support the CSS operation with wet steam, and 33% being used for
the steamflood as dry steam. As the CSS resource continues to be
depleted, a SAGD development is implemented, resulting in 33% of
the steam capacity being used for CSS (wet steam), 33% being used
for the steamflood (dry steam) and 33% now being used in a new SAGD
development (dry steam). Later, the CSS operations are completed
and 33% of the steam capacity supports a steamflood (dry steam) and
67% is used to support an expanded SAGD development (dry
steam).
[0091] The development with the CSS process may be supported by the
steam generation system 300 discussed with respect to FIG. 3, which
may represent a starting point for the installed steam capacity of
the development. At some point, the CSS production may no longer be
economical, and a development decision is made to convert a portion
of the existing development to a steamflood. Although, a new steam
generation system may be installed to create the dry steam this may
be costly. Accordingly, in an embodiment, one of the three steam
generators is converted to dry service.
[0092] FIG. 7 is a drawing of a steam generation system 700 after
conversion of one steam generator 206 to the production of dry
steam. Like numbered items are as described in the figures above.
The wet steam 208 produced from the converted steam generator 206
is sent to a separator 404 where the dry steam 402 is separated and
then sent to the field via a dry steam pipeline. This may be termed
the first steam system 702. The separated condensate 406 from the
first steam system 702 can then be cascaded to the inlet 704 of a
second steam system 706 that has another steam generator 206. The
net effect of the cascading arrangement is a comparable reduction
in the boiler feed water 205 provided to the second steam system
706 from the water treatment facility 204. Thus, water consumption,
operating costs, and energy consumption are reduced.
[0093] The wet steam 208 generated in the second steam system 706
has an increased level of contaminants, which may necessitate a
reduction in the steam quality generated in the second steam system
706. For example, if the concentration of the contaminants in the
wet steam 208 from the second steam system 706 exceeds a
precipitation limit, the contaminants may precipitate in the tubes
of the steam generator 206, causing damage. However, as the wet
steam 208 from the second steam system 706 may be used for a
recovery process where wet steam 208 is acceptable, a reduction in
quality may not materially impact recovery performance. The wet
steam 208 from the two remaining steam systems 706 and 708 is
combined to form a single wet steam stream 302, which is sent to
the remaining CSS wells. At some point, as mentioned above, a
further reduction in CSS may be desired, and more capacity may be
converted to the production of dry steam 402.
[0094] If an increase in wet steam may be useful, a bypass line 710
can be included to allow wet steam 208 from the first steam system
702 to bypass the separator 404 and add to the amount available for
the wet steam stream 302. For example, this may be useful if a new
portion of the development is opened, increasing the wet steam
demand after the conversion. As described below, further increases
in dry steam may be achieved by adding or directing wet steam 208
from the second steam system 706 to the inlet 712 of the third
steam system 708, as described with respect to FIG. 8.
[0095] FIG. 8 is a drawing of a steam generation system 800 after
conversion of two steam generators 206 to the production of dry
steam. Like numbered items are as described above. Wet steam 208
from the second steam system 706 is sent to a separator 404 where
the dry steam 402 is separated, mixed with the dry steam 402 from
the first steam system 702, and then sent to the field via a dry
steam pipeline. The separated condensate 406 from the second steam
system 706 is cascaded to the inlet 712 of the third steam system
708. Again, the net effect of this cascading action is a comparable
reduction in the boiler feed water provided to the third steam
system 708 from the water treatment facility 204 and, hence, a
further reduction in water consumption, operating costs, and energy
use.
[0096] The wet steam 208 generated in the third steam system 708
has a further increased level of contaminants, which may also
necessitate a reduction in the steam quality generated in this
third steam system 708. As the wet steam 208 may be used for a
recovery process, e.g., CSS, where wet steam is acceptable, a
reduction in quality may not materially impact recovery
performance. The wet steam 208 from the remaining steam system 708
is sent to the remaining CSS wells as wet steam stream 302.
[0097] As discussed with respect to FIG. 7, the configuration shown
in FIG. 8 may include bypass lines 710 to allow the wet steam 208
from the first steam system 704 and the second steam system 706 to
bypass the separators 404. This may allow for an easy conversion
back to wet steam 208 production from each system, if the amount
used for the wet steam stream 302 to the wells increases.
[0098] FIG. 9 is a drawing of a steam generation system that may
provide similar production of wet and dry steam as described for
FIGS. 7 and 8. Like numbered items are as described above. In this
case the steam generators 206 each feed a wet steam 208 into a
common wet steam header 902. A first portion 904 of the wet steam
208 may be sent to a field as the wet steam stream 302. The
remaining portion 906 of the wet steam 208 from the wet steam
header 902 is sent to a separator 404, from which the dry steam 402
may be sent to a field. The condensate 406 can be recycled to the
feed water header 908, displacing a comparable quantity of boiler
feed water 205 from the water treatment facility 204.
[0099] In this design, a reasonably continuous demand for wet steam
208 from all three steam generators 206 may help to ensure that the
contaminant levels in the boiler feed water header 908 remain at
acceptable levels. Further, the dilution of the condensate 406 in
the boiler feed water header 908 may be uniform across the inlets
of all three generators 206, uniformly lowering the concentration
of contaminants. This design may be more flexible in its ability to
respond to short term swings in the demand for wet steam 208 and
dry steam 402 than, for example, the configuration shown in FIG.
8.
[0100] FIG. 10 is a drawing of a steam generation system 1000 that
may not provide material steam-quality improvement, but may provide
significant operating flexibility. Like numbered items are as
described above. As described for FIG. 9, the steam generators 206
all feed into a common wet steam header 902, with a portion 906 of
the wet steam 208 being sent to a separator 404. From the separator
404, the dry steam 402 can be sent to the injection wells via a dry
steam pipeline. The separated condensate 406 can then be combined
with the remaining wet steam 208 and sent to the field as wet steam
stream 302.
[0101] This design may be beneficial when the expected demand for
dry steam 402 is small relative to the demand for wet steam 208, as
the impact of the quality of the wet steam 208 will be small. It
may also be used when the recovery process utilizing the wet steam
208 is not impacted by significant reductions in quality. For
example, supplying the heat used for a thermal recovery process
used in a surface mining project, such as a Clark hot water process
used to extract hydrocarbons from oil sands.
[0102] FIG. 11 is a drawing of the systems of FIGS. 7 and 8 after
the third steam system 708 is converted to dry steam service. Like
numbered items are as described above. In the third steam system
708, wet steam 208 is sent to a separator 404 where the dry steam
402 is separated and then combined with dry steam 402 from the
first steam system 702 and the second steam system 706, and sent to
the field via a dry steam pipeline. Again, the net effect of the
cascading condensate 406 from the first steam system 702 and the
second steam system 706 is an increase in the concentration of
contaminants in the condensate. As less and less wet steam 208 is
used in the development, these contaminants will need to be reduced
by other techniques. For example, the condensate 406 from the third
steam system 708 may be sent to disposal 408. With no additional
wet steam requirements, the existing wet steam pipeline can be
converted to dry steam service.
[0103] As for the configurations discussed with respect to FIGS. 7
and 8, the conversion process piping has bypass lines 710 to allow
the steam generation system 1100 to revert to an increase in
production of wet steam 208. Thus, as fluctuations in a balance
between wet steam 208 and dry steam 402 change with time, the steam
generation system 1100 has the flexibility to adapt to these
changing needs. For example, this flexibility allows the steam
generation system 1100 to provide a different balance of steam if
production is started in a new area of the development.
[0104] The process of cascading the condensate 406 between the
parallel steam systems 702, 706, and 708 will result in lower steam
systems 706 and 708 operating at a lower pressure than the steam
system 702 and 706 from which the condensate 406 was sourced. This
will result in the wet steam 208, for example, to be used in the
CSS recovery process, being provided at the lowest pressure of the
steam systems 702, 706, and 708. While this outcome may be
satisfactory if a CSS process is utilizing sub-fracture pressures
for steam injection, it may be problematic if higher pressures are
useful.
[0105] In situations where it is useful to operate all of the steam
systems 702, 706, and 708 at the same discharge pressure or to
operate the wet steam 208 at a higher discharge pressure, the
pressure of the condensate 406 being cascaded can be boosted using
a pump. If this is to be done while the condensate 406 is hot, the
design can account for the frictional pressure drop by increasing
the head gain from the base of the separator 404. This may be
useful for preventing steam vapor from forming at the pump suction,
which could lead to cavitation.
[0106] If the pumping is to be done after the condensate 406 is
cooled, then a beneficial use may be made of the heat contained in
the condensate 406. For example, one option would be to exchange
the heat of the condensate 406 with the boiler feed water stream as
it is entering a hot lime softener (HLS) in the water treatment
facility 204. This may reduce the steam consumed in the HLS
operation.
[0107] FIG. 12 is a drawing of a steam generation system 1200 in
which three steam systems 702, 706, and 708 operate in parallel and
generate dry steam 402 by cascading the condensate 406 sequentially
to the inlet 704 and 712 of the adjacent steam system 706 and 708.
Like numbered items are as described above. For purposes of
clarity, this drawing has been simplified from the steam generation
system of FIG. 11 by the elimination of the bypass lines 710 used
to reverse the conversion, e.g., to allow the production of wet
steam 208.
[0108] The current techniques allow dry stream 402 to be generated
using water with the least quantity of contaminants. Blending the
cascaded condensate 406 with the feed water helps to moderate the
concentration of the contaminants in an adjacent steam system 706
and 710. In this way the steam systems used for dry steam 402 have
the potential to generate higher quality steam than the remaining
steam generators being used for wet steam service.
[0109] FIG. 13 is a drawing of a steam generation system 1300
showing that the cascading process may be applied to steam systems
1302, 1306, and 1308 having multiple steam generators 206 operating
in parallel. Like numbered items are as described above. Thus, the
first steam system 1302 has two steam generators 206 in parallel in
this example. The wet steam 208 is passed to a separator 404, with
the condensate 406 from the separator 404 fed to the inlet 1304 of
the two steam generators 206 in the second steam system 1306.
Similarly, the condensate 406 from the second steam system 1306 is
fed to the inlet 1310 of the two steam generators 206 in the third
steam system 1308.
[0110] The steam generation system 1300 may also be used to present
a simplified material balance showing the beneficial effects of
cascading the condensate 406 between the steam generators 206 as
the steam generators 206 are converted from wet steam service to
dry steam service. For purposes of this example, it may be assumed
that each of the steam generators 206 is processing 100 units of
water and is generating steam with an 80% quality, i.e., providing
80 units of steam. Thus, the treatment facility 204 may have been
designed to process 600 units of feed water stream 202 from point 1
(as indicated by the numbered diamond). At point 2, 200 units of
the feed water from the treatment facility 204 are consumed by the
first steam system 1302, i.e., 100 units in each steam generator
206. The separator 404 separates the wet steam 208 from the steam
generators 206 into 160 units of dry steam at point 3 and 40 units
of condensate 406 at point 4. The condensate 406 is sent to the
inlet 1304 of the second steam system 1306. Thus, at point 5, 160
units of boiler feed water 205 from the water treatment facility
204 is used to give a total water feed to the second steam system
1306 of 200 units.
[0111] The wet steam 208 from the steam generators 206 of the
second steam system 1306 is fed to a separator 404, which separates
the wet steam 208 into 160 units of dry steam at point 6 and 40
units of condensate at point 7. The condensate 406 from the second
steam system 1306 is fed to the inlet 1310 of the third steam
system 1308. Thus, at point 8, 160 units of boiler feed water 205
from the water treatment facility 204 is used to provide a total
water feed of 200 units to the third steam system 1308.
[0112] The wet steam 208 from the steam generators 206 of the third
steam system 1308 is fed to a separator 404, providing 160 units of
dry steam at point 9. The dry steam 402 from the first steam system
1302, the second steam system 1306, and the third steam system 1308
is combined to give a total of 480 units of dry steam 402 at point
10, which may be sent to the injection wells in a development. The
40 units of condensate 406 from the separator 404 of the third
steam system 1308 will have the highest concentration of
contaminants, and can be sent to disposal at point 11. Thus, by
converting all three steam systems 1302, 1306, and 1308 to dry
steam service, 80 units of feed water that could be provided from
the water treatment facility 204 are freed for other purposes, such
as increasing the amount of steam that may be generated.
[0113] FIG. 14 is a drawing of a steam generation system 1400 that
includes a seventh steam generator 206 installed in a fourth steam
system 1402. Like numbers are as described before, and the mass
balance at similarly numbered points is the same as discussed with
respect to the steam generation system 1300 of FIG. 13.
[0114] In contrast to disposing of all of the condensate 406 from
the third steam system 1308, as shown in FIG. 13, the condensate
406 may be divided into two equal portions. A first portion of 20
units, indicated at point 12, may be fed to the inlet 1404 of the
fourth steam system 1402. Thus, the remaining 80 units of capacity
from the feed water treatment facility 204 are used to provide 100
units to the fourth steam system 1402 at point 13. The wet steam
208 from the steam generator 206 in the fourth steam system 1402 is
passed to a separator 404, resulting in 80 units of dry steam 402
at point 14. The dry steam 402 at point 14 can be combined with the
480 units of dry steam at point 10, to provide 560 units of dry
steam 402 to the injection wells at point 15.
[0115] The remaining portion of 20 units of condensate from the
separator 404 of the third steam system 1308, at point 16, may be
combined with the 20 units of condensate from the separator 404 of
the fourth steam system 1402 at point 17, resulting in 40 units of
condensate 406 which may be sent to disposal at point 11. As a
result all of the available water treatment capacity is being
utilized. Although the fourth steam system 1402 generator is shown
in dry steam service, it could be used in either wet steam or dry
steam service.
[0116] In an embodiment, the surplus capacity for boiler feed water
205 may be utilized by increasing the throughput of the existing
steam generators 206. This may be done when the objective is to
produce dry steam without compromising the design constraints,
e.g., by installing more steam generators 206.
Modification of a Steam Generator to Increase Inherent Capacity
[0117] In an embodiment, a steam generator 206 may be modified to
increase capacity by functioning like a series of smaller steam
generators. This may also have the additional benefit of increasing
the throughput through the steam generator 206.
[0118] FIG. 15 is a drawing of a steam generator 1500 that is
modified to increase both throughput and dry steam production. The
steam generator 1500 may contain multiple tube bundles arranged
into sections, including section A 1502, section B 1504, section C
1506, and section C' 1508. The outlet of each tube bundle provides
the inlet feed for the next tube bundle, with the exception of
sections C 1506 and C' 1508, which may be placed in parallel to
provide a spare section while one tube bundle is out of service for
cleaning or tube replacement. Embodiments are not limited to steam
generators that have segmented tubing bundles. In some embodiments,
the tubing may be contiguous prior to modification, and each tube
may be modified to direct the steam and water to a separator.
Further, the modification may be done on groups of tubes as a
unit.
[0119] In the steam generator 1500, the feed water 1510 is fed into
the tube bundle of section A 1502. The feed water 1510 may be
boiler feed water 205 from the water treatment facility 204, or may
be a blend of boiler feed water 205 and condensate 404. An
intermediate take-off 1512, for example, located after tubes in
section A 1502, diverts the steam and water from section A 1502 to
a separator 1514, which separates the dry steam 1516 from the
condensate 1518. The separator 1514 may be a conventional gravity
driven separator or may be a centrifugal separator used to form
liquid and vapor streams by centripetal force.
[0120] The condensate 1518 is then returned to the steam generator
1500 as the feed to section B 1504. The number, and/or diameters,
of tubes in each section 1502 and 1504 do not have to match. For
example, a larger number of tubes in section A 1502 may be used to
feed a smaller number of tubes in section B 1504 or vice-versa.
[0121] Similarly, an intermediate take-off 1520 after the tubing
bundle of section B 1504 diverts the steam and water to another
separator 1522, which separates the dry steam 1524 from the
condensate 1526. The condensate 1526 may then be sent to a last
section of the steam generator 1500. The separators 1514 and 1522
do not have to be individual.
[0122] The separators 1514, 1522, and 1530 do not have to be
individual. In some embodiments, a single separator may be used for
all of the take-off points 1512, 1520, and 1528. If a single
separator is used, internal weirs or other segmentation devices may
be used to create compartments to separate the condensate streams,
minimizing the mixture of condensate having different levels of
contaminates. One or more pumps may be used to boost the pressure
of the condensate 1518 or 1526 that is returned to the steam
generator 1500.
[0123] The water quality will be poorest in the last section, and
thus the risk of scale deposition will be greatest at that point.
Accordingly, two "third sections," for example, section C 1506 and
C' 1508, can be included in the design to help with the increased
risk from scale. The use of two final sections 1506 and 1508 allows
the diversion of the condensate 1526 and any hot gases into the
replacement section while the tubes are being replaced in an
off-line third section. This allows the steam generator 1500 to
increase steam quality over a single section, as the steam
generator 1500 can be operated much closer to the contaminant
solubility limit without the fear of having to shutdown the entire
unit in case a tube failure occurs. Thus, the condensate 1526 may
be sent to either section C 1506 or section C 1508, depending on
which is operational at the time. In some embodiments, both
sections 1506 and 1508 may be operated together to increase the
overall yield of the steam generator 1500. Further, the extra
section may be shared with an adjacent steam generator to provide a
spare for two steam generators with lower capital costs.
[0124] As shown, the intermediate take-offs 1512 and 1520 along the
boiler tubes preferentially remove the steam to allow the
condensate 1518 and 1526 to continue within the steam generator
1500. For example, if an intermediate take-off was located at the
point where the steam quality was predicted to first achieve 55%,
and a second intermediate take-off was located where the steam
quality was predicted to achieve 55% for a second time, and the
final steam quality existing the steam generator 1500 was also 55%,
the overall steam quality created by the steam generator 1500 would
be .about.90%, or around 10% greater than may be generated without
the intermediate takeoffs. However, it can be noted that the steam
quality produced in each section may or may not be the same.
[0125] The wet steam 1528 from section C 1506 and section C' 1508
is sent to a final separator 1530, which separates the dry steam
1532 from the condensate 1534. The condensate 1534 may be sent to
disposal or to a water treatment facility for recycling. If the
contaminants are sufficiently low in the condensate 1534, it may be
in returned to the inlet of the same steam generator 1500, or to
the inlet of a successive steam generator. At least a portion of
the condensate 1534 may be treated or disposed to control the
build-up of contaminants. Further, a takeoff from the wet steam
1528 may be used to provide a wet steam stream 1538 to a
development. In this case, the condensate stream 1534 may be
blended with the wet steam stream 1538 for disposal, since the
extra contaminants will not harm the wet steam stream 1538.
[0126] The individual separated dry steam 1516, 1524, and 1532 is
then combined into a dry steam stream 1536, which may be sent to
injection wells via a pipeline. In this example two intermediate
take-offs 1512 and 1520 are used to reset the steam quality in the
steam generator 1500 back to zero at the beginning of each section
1502, 1504, 1506, and 1508. As a result, the peak velocities in the
boiler tubes are reduced allowing the maximum allowable flow rate
per boiler tube to be increased. The higher condensate content in
the boiler tubes also allows a higher heat flux to be used with the
boiler tubes, thereby allowing a higher rate for the boiler feed
water 1510, increasing the amount converted to dry steam 1536.
Extra boiler feed water 1510 may be added to each of the individual
sections 1504, 1506, or 1508, through a feed water line 1540. This
enables the modified steam generator 1500 to function in an
analogous fashion to the steam generation systems shown in FIGS.
7-14.
[0127] The configuration of the steam generator 1500 shown in FIG.
15 may have a number of advantages over current steam generators.
For example, the sequential removal of steam from the tubing
reduces the peak velocities, thereby increasing the maximum
allowable flow rate per boiler tube. Further, the higher condensate
content in each boiler tube, e.g., due to lower steam quality in
the tube, allows a higher heat flux to be used with the boiler
tubes, thereby allowing more boiler feed water to be converted to
steam. The modified steam generator may be implemented for a wide
range of project sizes.
Tailoring Steam Generation to Field Usage
[0128] FIG. 16 is a process flow diagram of a method 1600 for
tailoring the quality of steam production to field needs. The
method 1600 may be used to improve thermal recovery processes for a
hydrocarbon reservoir that is exploitable through surface mining,
subsurface mining, in situ techniques, or any combinations
thereof.
[0129] The method 1600 starts at block 1602 by matching thermal
recovery processes with specific reservoir regions within the
development to achieve optimal resource recovery. To begin, the
reservoirs expected to be developed over the life of the project
are delineated. Reservoir delineation typically occurs through the
combined use of delineation wells, remote sensing technologies such
as 2D and 3D seismic studies, studies of modern analogs and outcrop
studies of the target reservoir, for example, if parts of the
reservoir outcrop on surface, or studies of other reservoirs with
comparable depositional setting. Remote sensing technologies,
modern analogs, and outcrop studies allow the prediction of the
spatial distribution of the reservoir attributes through the
reservoir.
[0130] Delineation wells are used to collect core samples of the
target reservoir and to collect log data, both for open hole and
cased hole wells. The cores may be used to gain an understanding of
the depositional settings present in the reservoir, porosity and
oil content distributions, horizontal and vertical permeability
distributions, oil density and viscosity information, sand grain
size analyses and reservoir rock samples that can be used to
understand how the reservoir material will respond to heating with
steam or water. The core samples may be used to identify the ease
with which the hydrocarbons can be separated from the reservoir
fabric during surface extraction operations. The delineation wells
may also be used to collect data detailing the ability of the
reservoir caprock to withstand increases in pressure as a result of
steam injection, and the initial pressure distribution in the
reservoir. Further, they can aid the identification of the presence
and areal extent of any pressure sinks, or intervals that may
require dewatering, such as top gas, top or bottom water. This may
include interstitial intervals with the reservoir that have initial
enhanced water mobility, present in or in proximity to the oil
bearing sections. Further, the data may be used to identify
locations and capacities, of water make-up sources and water
disposal intervals.
[0131] The data can be used to create a geologic model for each
reservoir that is expected to be developed as part of the overall
development. These geologic models can be constructed using a
geologic modeling software program. The available open hole and
cased hole log, core, 2D and 3D seismic data, and knowledge of the
depositional environment setting may be used in the construction of
the geologic model.
[0132] The attributes of various recovery processes can be used to
interrogate the geologic models to identify the areas of the
reservoirs that have attributes amendable to the various recovery
processes. For example, a recovery process that relies on the
ability to cycle pressures, such as CSS, would not be a preferred
recovery process when developing a portion of a reservoir where an
extensive top gas interval is present. Further, a surface mining
process would not work for a deep reservoir.
[0133] At block 1604 the overall depletion strategy is designed to
optimize the field design, steam generation and water treatment
facilities for the entire life of the recovery project. For each
combination of reservoir description and recovery technology, a
series of performance predictions can be made using a reservoir
simulation program, or a mine planning program. It may also be
possible to use simple empirical or analog based models for
performance prediction.
[0134] In many cases, follow-up recovery processes can be used to
further enhance the recovery of the hydrocarbon. These options to
extend recovery can be considered during the planning phase to
assist in determining designs for resources.
[0135] A combination of simple economic models, performance
expectations for a recovery process, and field layout and
infrastructure considerations can be used to optimize the overall
sequence for the development. This knowledge may then be used to
identify the remaining acquisition requirements for reservoir data
and the timing of their capture.
[0136] As further data is acquired, the geologic models will
continue to evolve over time. Once the geologic models have
demonstrated the capability to reasonably predict the results for a
planned recovery technology, for example, as observed in recently
drilled delineation wells, the geologic data collected may be
considered sufficient. In addition, a commercial thermal
development may typically have an operating life of 20-50+ years.
Thus, the existing thermal recovery processes may continue to
evolve and new thermal recovery processes will continue to develop.
Accordingly, the steam generation facility can be designed to
respond to future shifts in steam quality used by the
development.
[0137] At block 1606, the factors are identified that indicate the
time to convert to a different steam quality to support a different
mix of recovery processes. To this point in the development
planning process, the actual design of the steam generation
facilities is not considered, other than keeping the design
flexible with regard to steam quality. For example, it may be
useful for a steam generation facility to initially generate only
wet steam and then, over time, see a need to generate progressively
larger fractions of dry steam ending with a need for only dry
steam. Similarly, it may be useful to switch back and forth between
generating primarily wet steam to primarily dry steam multiple
times over the life of the development.
[0138] At block 1608, the steam generation facility is installed
during development of the field. The wells are completed to the
reservoir, and any surface mining processes are started. The
initial thermal recovery processes that use the wells, such as CSS,
may be started at this point. To illustrate the process, various
thermal recovery processes are described herein. However,
embodiments are not limited to the processes described, but may be
used with any thermal recovery process. The steam used for the
initial thermal recovery processes may be wet, as discussed
above.
[0139] As production from the CSS falls, a portion of the wells may
be converted to steamflood. Further, other wells may be drilled in
the reservoir to begin SAGD recovery processes in other regions.
Primary SAGD processes are known to be more effective when dry
steam is used.
[0140] At block 1610, the steam generation facility is transitioned
from producing mostly or all wet steam to producing some amount of
dry steam, for example, by converting a first steam system to dry
steam production. For a development scenario where a newly started
thermal recovery process requires dry steam, wet steam can also be
generated, for example, using parallel or adjacent steam systems as
described herein.
[0141] In an embodiment, at the exit of a first steam system, the
steam and condensate can be separated with the condensate being
directed to the inlet of an adjacent steam system where it is used
as a part of the feed water. At the exit of the second steam
system, the steam and condensate can be separated with the
condensate being directed to the inlet of the adjacent steam system
where it is used as a part of the boiler feed water stream. The
cascading may be continued across as many multiple steam systems to
meet the demand for wet steam versus dry steam.
[0142] This cascading of condensate between parallel steam systems
so arranged allows a higher overall steam quality to be generated,
as measured per unit of boiler feed water. The improvement in steam
quality is irrespective of the number of steam systems being used
in the development. In addition, if one of the parallel steam
systems is down for repair, the condensate can be cascaded to the
next available steam system, thus, maintaining the expected
benefits.
[0143] At block 1612, the water reuse is balanced against the steam
generation quality. As discussed, the concentration of contaminants
present in the boiler feed water will increase in a predictable
fashion along a row of cascaded steam systems. For example, if the
steam quality generated is 80% in each steam system, the sequential
blending of the condensate with the boiler feed water will cause
the contaminant loading to increase by 80% with each incremental
cascading of the condensate.
[0144] If the contaminant loading at the exit of the last steam
system in the cascade is predicted to be less than the solubility
limit, the opportunity exists to reduce the level of the boiler
water treatment, saving operating costs, and potentially capital.
However, if the contaminant loading at the exit of the last
parallel steam generator is predicted to be above the solubility
limit, then the steam quality generated in the last parallel steam
generators can be reduced to maintain solubility. Further, if the
contaminant loading at the exit of the last parallel steam system
is predicted to be above the solubility limit, then the steam
systems can be formed from parallel groups of two or more steam
generators, with the condensate cascaded between these steam
systems. The number of generators per steam system can be chosen to
ensure that solubility is maintained in the last group of
generators.
[0145] The processing of the condensate from the last steam system
in the cascade may be determined by a number of factors. These may
include the ability of the condensate to keep the contaminants
dissolved at the temperatures expected in the disposal process or
formation. If the potential for further concentration of the
condensate exists, the condensate can be dropped to a lower
pressure which will allow a portion of the water to flash to steam.
This steam can then be used as a heat source within the plant or
condensed and utilized as a make-up water source. Further, if water
is in short supply, the condensate may be passed to a water
treatment facility to remove a portion of the contaminants.
[0146] As described, the cascading of condensate between steam
systems may result in each steam system operating at a
progressively lower pressure. The hot condensate can be mixed with
current boiler feed water stream downstream of the high pressure
pump to ensure flashing does not occur in the next steam system. As
a result, the cooler temperatures can lower the pressure. If it is
desired to have all of the parallel steam systems operating at the
same pressure, or to have the later steam systems in the cascading
arrangement operate at a higher pressure than the earlier steam
system, pumps can be used to boost the pressure of the condensate
cascaded between the operated in parallel steam generators.
[0147] Continuing with this example, as development activities
evolve in this scenario and wet steam demand occurs, for example,
due to development in new areas of the field, the last steam
generator in the cascading arrangement can be returned to wet steam
service by bypassing the separation step at the exit of the steam
system. If the demand for wet steam increases further, additional
steam generators near the end of the cascading arrangement can be
converted to wet steam service. Conversely, if the short or long
term demand for dry steam were to increase, starting with the most
recently converted wet steam generator, the steam generators can be
easily converted back to dry steam service by completing the
separation step at the exit of the generator.
[0148] The techniques described herein may be applied to new
thermal development schemes or expansions to existing thermal
development schemes. They may also be retrofitted into existing
thermal based development schemes. The thermal recovery processes
can include surface mining, subsurface mining, such as slurrified
production of oil sands, and in situ opportunities, such as CSS,
steamflood, SAGD, and the like. The conversion of a facility
initially designed to generate wet steam to one capable of
generating dry steam, using the technique by cascading the
condensate between parallel steam system frees boiler feed water
treating capacity. If the development plan confirms that sufficient
surplus boiler feed water treating capacity will be available for a
sustained period of time, a new steam system, such as a single OTSG
or HRSG, can be installed to generate additional steam using the
now idle boiler feed water treatment capacity. By applying the
strategies outlined herein, this opportunity can be identified
early and, thus, plot space could be left to allow for the future
installation of this new steam system.
[0149] For both new development schemes and expansions to existing
development schemes, a novel configuration is available once it is
recognized that two design constraints in OTSG or HRSG design are
the exit velocity of the fluids and the heat flux along the tubing.
To decrease erosion, the maximum quantity of water fed into each
boiler tube can be constrained such that the maximum velocity
constraint is not exceeded at the exit of the boiler tubes. To help
prevent localized dry out conditions, and scale deposition in the
boiler tubes, the maximum heat flux can also be constrained,
especially where it is anticipated that the steam quality in the
boiler tube will be higher.
[0150] By following the method for improving thermal recovery
processes from a subsurface hydrocarbon reservoir described herein,
either the cascading steam generation design, or the internally
segmented steam generator design, or a combination of both, may
provided the desired flexibility to meet both short and long term
shifts in the demand for wet and dry steam. For example, FIGS.
17-19 show examples of developments that can take advantage of the
steam systems discussed herein. Although a particular steam system
is shown for all three figures, corresponding to the system of FIG.
10, it can be noted that any of the systems in FIGS. 7-15 could be
used to supply steam for the developments.
[0151] FIG. 17 is a drawing of a development 1700 for which dry
steam is separated from the wet steam and the different steam lines
are directed to regions of the field where recovery processes
efficiently use the wet or dry steam. Like numbered items are as
discussed with respect to the prior figures. Although the steam
system shown in FIGS. 17-19 is essentially the system 1000
discussed with respect to FIG. 10, it can be understood that any of
the systems discussed with respect to FIGS. 7-15 may be used. In
this application, the dry steam 402 is supplied to the injection
well 1702 of a SAGD pair. Hydrocarbons may then be harvested from
the collection or production well 1704. The wet steam 302 from the
steam generators 206 may be directly supplied to a series of
steamflood wells 1706. The condensate 406 from the separator (or
any comparable condensate stream in FIGS. 7-15) can be added to the
wet steam 302 to reduce contaminates.
[0152] FIG. 18 is a diagram of a SAGD process 1800 with infill
wells 1802 where the efficiency of the process is enhanced by
directing dry steam to the SAGD injection wells 1804 and wet steam
to the infill well injectors. As for the development 1700 of FIG.
17, the SAGD process 1800 may allow any excess condensate 406 to be
blended with the wet steam 302 for injection into the reservoir
1806.
[0153] FIG. 19 is a drawing of configurations that may be used for
the co-injection of solvent and steam. In these configurations, the
solvent may be heated by exchanging heat with the wet steam 302, as
indicated by heat exchangers 1902 and 1904. The heat exchange may
vaporize the solvent before it is injected into the dry steam 402,
and injected with the dry steam 402 into the SAGD injection wells
1906. The wet steam 302 may be injected into infill wells 1908,
with or without mixing in excess condensate 406. Although the
solvent may be injected without the heating, the energy used to
vaporize the solvent will cause a fraction of the steam to condense
in the dry steam 402, lowering the efficiency of the process. If
more heat is needed, for example, to decrease the amount of
condensation in the wet steam, the solvent may be preheated by heat
exchanging with the feed water stream 202, for example, using
another heat exchanger 1910.
[0154] The above-described embodiments of the invention are
intended to be examples only. Alterations, modifications, and
variations can be effected to the particular embodiments by those
of ordinary skill in the art without departing from the scope of
the invention, which is defined solely by the claims appended
hereto.
Exemplary Embodiments
[0155] An exemplary embodiment provides a system for improved steam
generation that includes at least two steam systems, wherein a wet
steam output from a first steam system is passed through a first
separator. The first separator is configured to separate dry steam
from condensate. A piping connection is configured to supplement a
boiler feed water stream with the condensate at the inlet of a
second steam system. The amount of condensate supplementing the
boiler feed water stream is changed based, at least in part, on a
demand for dry steam.
[0156] In some embodiments, a steam system includes a once-through
steam generator, or a heat recovery steam generator, or a
combination thereof.
[0157] In some embodiments, the system includes a hydrocarbon
development such as a cyclic steam stimulation process, a
steamflood process, a steam assisted gravity drainage process, a
thermal solvent process, a sub-surface mining operation, or a
surface mining operation, or any combinations thereof.
[0158] In some embodiments, the system is configured to produce wet
steam, dry steam, or a combination thereof.
[0159] In some embodiments, the system includes a second separator
on the wet steam output from the second steam system configured to
separate dry steam from condensate and piping to feed the
condensate to an inlet on a third steam system in a blend with
boiler feed water.
[0160] In some embodiments, the system includes a number of thermal
recovery processes in a hydrocarbon development. A first portion of
the plurality of thermal recovery processes may be configured to
use a wet steam stream and a second portion of the plurality of
thermal recovery processes may be configured to use a dry steam
stream.
[0161] Another exemplary embodiment provides a method for improving
recovery from a hydrocarbon reservoir. The method includes matching
a steam quality to a hydrocarbon development, wherein the steam is
generated by a steam generation facility that includes a number of
steam systems. The steam generation facility is adapted to match a
change in steam usage caused by a change in the hydrocarbon
development. As used herein, adapting includes cascading a
condensate stream from a separator on an outlet of at least one
steam system to an inlet of another steam system and replacing a
portion of boiler feed water stream with the condensate stream at
the inlet. The portion of boiler feed water replaced is determined
by a ratio of dry steam to wet steam used in the hydrocarbon
development.
[0162] In some embodiments, the method includes performing a
plurality of thermal recovery processes on regions within the
hydrocarbon development, wherein different recovery processes are
used for different regions or at different times.
[0163] In some embodiments, the method includes performing a
solvent assisted thermal recovery process in a hydrocarbon
development. In the solvent assisted thermal recovery process, a
solvent stream can be vaporized by a heat exchanger sourcing heat
from a wet steam line. The vaporized solvent stream can then be
combined with dry steam.
[0164] In some embodiments, the method includes transitioning the
steam generation facility from wet steam to dry steam.
[0165] In some embodiments, the method includes balancing water
reuse with steam generation to keep dissolved solids from
precipitating in a steam system.
[0166] In some embodiments, the method includes sequentially
converting a number of steam systems from wet steam service to dry
steam service to match a change in the steam quality used in the
hydrocarbon development. A portion of the steam systems can be
reverted to wet steam service to match a change in the steam
quality used in the hydrocarbon development.
[0167] In some embodiments, the method includes adjusting the steam
quality at the exit of each of the plurality of steam systems to
ensure that contaminants present in a boiler feed water remain
soluble in the steam system.
[0168] In some embodiments, the method includes adding a steam
system to the plurality of steam systems to utilize surplus boiler
feed water freed when converting a steam system from wet steam
service to dry steam service.
[0169] In some embodiments, the method includes shutting-in steam
systems as a result of a reduction in boiler feed water resulting
from a conversion of a portion of the steam systems from wet steam
service to dry steam service.
[0170] In some embodiments, the method includes drilling a number
of infill steam injection wells between each of a number of steam
assisted gravity drainage (SAGD) wellpairs. Dry steam can be
injected into a steam injection wells in the SAGD wellpairs; and
wet steam can be injected into the infill steam injection
wells.
[0171] In some embodiments, the method includes injecting dry steam
into a plurality of steam injection wells in a plurality of steam
assisted gravity drainage (SAGD) wellpairs, and injecting wet steam
into a plurality of steamflood wells.
* * * * *