U.S. patent application number 13/471928 was filed with the patent office on 2012-12-13 for enhanced hydrocarbon recovery through gas production control for noncondensable solvents or gases in sagd or es-sagd operations.
This patent application is currently assigned to ConocoPhillips Company. Invention is credited to Tawfik N. Nasr, Thomas J. Wheeler.
Application Number | 20120312534 13/471928 |
Document ID | / |
Family ID | 46298662 |
Filed Date | 2012-12-13 |
United States Patent
Application |
20120312534 |
Kind Code |
A1 |
Nasr; Tawfik N. ; et
al. |
December 13, 2012 |
ENHANCED HYDROCARBON RECOVERY THROUGH GAS PRODUCTION CONTROL FOR
NONCONDENSABLE SOLVENTS OR GASES IN SAGD OR ES-SAGD OPERATIONS
Abstract
Methods are provided for enhancing hydrocarbon recovery through
gas production control for noncondensable gases in SAGD or ES-SAGD
operations. Steam may be injected into one or more injection wells
to heat the hydrocarbons and reduce their viscosity to more easily
produce the hydrocarbons. A noncondensable gas may be injected into
the injection wells to beneficially reduce the steam-to-oil ratio,
improving economic recovery. Unfortunately, excessive production of
noncondensable gases can adversely suppress hydrocarbon production
rates. To counteract this problem, gas production rates at the
production wells may be controlled to optimize hydrocarbon output
by limiting the produced gas-to-water ratio to certain limited
ranges. The noncondensable gas may optionally comprise a combustion
gas such as flue gas. By providing a useful application of existing
combustion gases, green house gases emissions may be reduced.
Advantages include higher efficiencies, lower costs, reduced
hydrocarbon extraction time, and in some embodiments, reduced
greenhouse gas emissions.
Inventors: |
Nasr; Tawfik N.; (Katy,
TX) ; Wheeler; Thomas J.; (Houston, TX) |
Assignee: |
ConocoPhillips Company
Houston
TX
|
Family ID: |
46298662 |
Appl. No.: |
13/471928 |
Filed: |
May 15, 2012 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61494226 |
Jun 7, 2011 |
|
|
|
Current U.S.
Class: |
166/272.3 |
Current CPC
Class: |
E21B 43/2408 20130101;
E21B 43/168 20130101; E21B 43/12 20130101 |
Class at
Publication: |
166/272.3 |
International
Class: |
E21B 43/24 20060101
E21B043/24 |
Claims
1. A method for enhancing recovery of bitumen or heavy oil from a
low mobility reservoir comprising the steps of: providing one or
more injection wells wherein the one or more injection wells
intersect the heavy oil reservoir; providing one or more production
wells wherein the one or more production wells intersect the heavy
oil reservoir; wherein the one or more injection wells and the one
or more production wells are paired to form a SAGD or ES-SAGD
process; producing steam via a steam generator wherein flue gas is
produced as a byproduct of the steam generator; introducing the
steam into one of the one or more injection wells; introducing the
flue gas into one of the one or more injection wells; allowing a
production flow to be produced from the one or more production
wells wherein the production flow comprises a production gas flow
and a production water flow; determining a production gas-to-water
ratio as a ratio of the production gas flow to the production water
flow; and limiting the production flow to obtain a production
gas-to-water ratio in the production flow from about 1 to about
30.
2. The method of claim 1 wherein the step of introducing steam
comprises the step of continuously introducing the steam into one
of the one or more injection wells and wherein the step of
introducing the flue gas comprises the step of continuously
introducing the flue gas into one of the one or more injection
wells.
3. The method of claim 1 wherein the step of introducing steam
comprises the step of intermittently introducing the steam into one
of the one or more injection wells and wherein the step of
introducing the non-condensable gas comprises the step of
intermittently introducing the non-condensable gas into one of the
one or more injection wells.
4. The method of claim 1 wherein the steam and the non-condensable
gas are combined into a single stream for injection into the one or
more injection wells.
5. The method of claim 2 wherein the steam and the non-condensable
gas are combined into a single stream for injection into the one or
more injection wells.
6. The method of claim 1 wherein the production gas-to-water ratio
is about 1 to about 10.
7. The method of claim 1 wherein the production gas-to-water ratio
is about 1 to about 5.
8. The method of claim 1 wherein the production gas-to-water ratio
is about 5 to about 10.
9. A method for enhancing recovery of bitumen or heavy oil from a
low mobility reservoir comprising the steps of: providing an
injection well wherein the injection well extends into the heavy
oil reservoir via an upper horizontal well; providing a production
well wherein the production well extends into the heavy oil
reservoir via a lower horizontal well; continuously introducing
steam and a non-condensable gas into the injection well; allowing a
production flow to be produced from the production well wherein the
production flow comprises a gas flow and a water flow; determining
a production gas-to-water ratio as a ratio of the production gas
flow to the production water flow; and limiting the production flow
to obtain a production gas-to-water ratio from about 1 to about
10.
10. The method of claim 9 wherein the injection well and the
production well are paired to form a SAGD or ES-SAGD process.
11. The method of claim 9 wherein the non-condensable gas is
butane.
12. The method of claim 9 wherein the non-condensable gas is
methane, ethane, propane, butane, air, oxygen, nitrogen, hydrogen,
carbon dioxide, carbon monoxide, combustion gases from a control
device or other direct combustion device, combustion gases from a
direct steam generator, flue gas, or any combination thereof.
13. The method of claim 9 further comprising the step of providing
a direct steam generator wherein the direct steam generator
produces a combined output stream of steam and flue gas, wherein
the non-condensable gas is the flue gas from the direct steam
generator.
14. The method of claim 13 wherein the production gas-to-water
ratio is about 1 to about 10.
15. The method of claim 13 wherein the production gas-to-water
ratio is about 1 to about 5.
16. The method of claim 13 wherein the production gas-to-water
ratio is about 5 to about 10.
17. The method of claim 13 wherein the step of continuously
introducing steam and a non-condensable gas into the injection well
further comprises the step of continuously introducing steam and a
non-condensable gas into the injection well to form an injection
flow that comprises an injection gas flow and an injection water
flow, wherein the method further comprises the step of determining
an injection gas-to-water ratio as a ratio of the injection gas
flow to the injection water flow, wherein the injection
gas-to-water ratio is from about 50 to about 100.
18. The method of claim 13 further comprising the step of
introducing a solvent into the injection well.
19. The method of claim 17 wherein the solvent comprises
hexane.
20. The method of claim 17 wherein the solvent is carbon dioxide,
an aliphatic hydrocarbon having 4 carbons to 30 carbons, naptha,
syncrude, diesel, an aromatic solvent, toluene, benzene, xylene, or
any combination thereof.
21. The method of claim 20 wherein the solvent is a light
non-condensable hydrocarbon solvent having one to four carbons.
22. The method of claim 10 further comprising: providing a direct
steam generator wherein the direct steam generator produces a
combined output stream of steam and flue gas, wherein the
non-condensable gas is the flue gas from the direct steam
generator; wherein the non-condensable gas is methane, ethane,
propane, butane, air, oxygen, nitrogen, hydrogen, carbon dioxide,
carbon monoxide, combustion gases from a control device or other
direct combustion device, combustion gases from a direct steam
generator, flue gas, or any combination thereof; wherein the
production gas-to-water ratio is about 1 to about 5; and
introducing a solvent into the injection well; and wherein the
solvent is carbon dioxide, an aliphatic hydrocarbon having 4
carbons to 30 carbons, naptha, syncrude, diesel, an aromatic
solvent, toluene, benzene, xylene, or any combination thereof.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application is a non-provisional application which
claims benefit under 35 USC .sctn.119(e) to U.S. Provisional
Application Ser. No. 61/494,226 filed Jun. 7, 2011, entitled
"ENHANCED HYDROCARBON RECOVERY THROUGH GAS PRODUCTION CONTROL FOR
NONCONDENSABLE SOLVENTS OR GASES IN SAGD OR ES-SAGD OPERATIONS,"
which is incorporated herein in its entirety.
FIELD OF THE INVENTION
[0002] The present invention relates generally to methods and
systems for enhancing hydrocarbon recovery through gas production
control for noncondensable solvents or gases in SAGD or ES-SAGD
operations.
BACKGROUND
[0003] Effective production of low mobility reservoirs such as
heavy oil and bitumen reservoirs presents significant challenges
and thus requires sophisticated technologies to produce
hydrocarbons efficiently from these types of reservoirs. These
difficulties are due to the complex nature of these types of
reservoirs and the low oil mobility at initial reservoir
conditions.
[0004] Low mobility reservoirs are characterized by high viscosity
hydrocarbons, low permeability formations, and/or low driving
forces. Extraction of high viscosity hydrocarbons is typically
difficult due to the relative immobility of the high viscosity
hydrocarbons. For example, some heavy crude oils, such as bitumen,
are highly viscous and therefore immobile at the initial viscosity
of the oil at reservoir temperature and pressure. Indeed, such
heavy oils may be quite thick and have a consistency similar to
that of peanut butter or heavy tars, making their extraction from
reservoirs especially challenging.
[0005] Conventional approaches to recovering such heavy oils often
focus on methods for lowering the viscosity of the heavy oil so
that the heavy oil may be produced from the reservoir, such as
heating the reservoir to lower the viscosity of the heavy oil.
Commonly used in-situ extraction thermal recovery techniques
include a number of reservoir heating methods, such as steam
flooding, cyclic steam stimulation, and Steam Assisted Gravity
Drainage (SAGD). SAGD is an enhanced oil recovery technology for
producing heavy crude oil and bitumen. It is an advanced form of
steam stimulation in which a pair of two superposed, vertically
separated horizontal wells is drilled into an oil reservoir, one a
few meters above the other, close to the bottom of an oil bearing
sand. Steam is continuously injected into the upper wellbore to
provide a driving force and simultaneously heat the oil and reduce
its viscosity, causing the heated oil to drain under the action of
gravity into the lower wellbore, where the oil is then pumped out.
This technique has been successfully applied in the field,
particularly in Canada, on a commercial scale in the last ten
years.
[0006] Steam injection processes, however, are energy and water
intensive processes due to the fact that the reservoir rock and
fluids must be heated to high temperatures and a significant
portion of injected energy is lost to the surrounding overburden
and underburden formations. These factors significantly reduce the
thermal efficiency of the process and can result in uneconomic
production of the hydrocarbons. Generally, approximately 2.5
barrels of water is converted to steam to produce one barrel of
oil. In addition, steam generation requires burning of fuel such as
natural gas that results in green house gas emissions.
[0007] Solvent injection processes, on the other hand, present
other challenges. While solvent injection processes typically
require less energy as compared to steam injection processes, the
solvent injection processes generally require large volumes of
expensive solvent and result in significant, costly solvent loss in
the reservoir. These costly solvent losses often render solvent
injection process economically disadvantageous.
[0008] Low driving forces can also adversely affect hydrocarbon
recovery. Where sufficient reservoir pressure is lacking to
motivate hydrocarbons to the surface, hydrocarbon production rates
may be limited to an economically unpractical production flow rate.
Secondary recovery operations are sometimes used to motivate
hydrocarbons suffering from low driving forces toward a production
well. One example of a secondary recovery is the use of steam
flooding to sweep hydrocarbons toward a production well. Steam
flooding involves the use of injected steam to heat and physically
displace hydrocarbons to encourage production of the
hydrocarbons.
[0009] Unfortunately, each of these conventional techniques suffers
from poor inefficiencies including high steam to oil ratios and
high solvent losses. Accordingly, there is a need for more
efficient enhanced recovery methods for recovering heavy oils from
low mobility reservoirs that address one or more of the
disadvantages of the prior art.
SUMMARY
[0010] The present invention relates generally to methods and
systems for enhancing hydrocarbon recovery through gas production
control for noncondensable solvents or gases in SAGD or ES-SAGD
operations.
[0011] One example of a method for enhancing recovery of bitumen or
heavy oil from a low mobility reservoir comprises the steps of:
providing one or more injection wells wherein the one or more
injection wells intersect the heavy oil reservoir; providing one or
more production wells wherein the one or more production wells
intersect the heavy oil reservoir; wherein the one or more
injection wells and the one or more production wells are paired to
form a SAGD or ES-SAGD process; producing steam via a steam
generator wherein flue gas is produced as a byproduct of the steam
generator; introducing the steam into one of the one or more
injection wells; introducing the flue gas into one of the one or
more injection wells; allowing a production flow to be produced
from the one or more production wells wherein the production flow
comprises a production gas flow and a production water flow;
determining a production gas-to-water ratio as a ratio of the
production gas flow to the production water flow; and limiting the
production flow to obtain a production gas-to-water ratio in the
production flow from about 1 to about 30.
[0012] One example of a method for enhancing recovery of bitumen or
heavy oil from a low mobility reservoir comprises the steps of:
providing an injection well wherein the injection well extends into
the heavy oil reservoir via an upper horizontal well; providing a
production well wherein the production well extends into the heavy
oil reservoir via a lower horizontal well; continuously introducing
steam and a non-condensable gas into the injection well; allowing a
production flow to be produced from the production well wherein the
production flow comprises a gas flow and a water flow; determining
a production gas-to-water ratio as a ratio of the production gas
flow to the production water flow; and limiting the production flow
to obtain a production gas-to-water ratio from about 1 to about
10.
[0013] The features and advantages of the present invention will be
apparent to those skilled in the art. While numerous changes may be
made by those skilled in the art, such changes are within the
spirit of the invention.
BRIEF DESCRIPTION OF THE DRAWINGS
[0014] A more complete understanding of the present disclosure and
advantages thereof may be acquired by referring to the following
description taken in conjunction with the accompanying figures,
wherein:
[0015] FIG. 1 illustrates an example of an enhanced heavy oil
recovery system in accordance with one embodiment of the present
invention.
[0016] FIG. 2 illustrates another example of an enhanced heavy oil
recovery system incorporating a direct steam generator.
[0017] FIG. 3 shows a graph of monthly average water injection rate
as a function of time comparing the cases of uncontrolled gas
production and controlled gas production.
[0018] FIG. 4 shows a graph of injection pressure versus time
comparing the cases of uncontrolled gas production and controlled
gas production.
[0019] FIG. 5 shows a graph of monthly averages of gas-to-water
ratios (GWR) versus time comparing the cases of uncontrolled gas
production and controlled gas production.
[0020] FIG. 6 shows a graph of cumulative oil production versus
time comparing the cases of uncontrolled gas production and
controlled gas production.
[0021] FIG. 7 shows a graph of cumulative steam-to-oil ratio (SOR)
versus time comparing the cases of uncontrolled gas production and
controlled gas production
[0022] FIGS. 8A, 8B, and 8C show a series of performance
comparisons. FIG. 8A shows a comparison of cumulative SOR. FIG. 8B
shows a comparison of reduction in percent SAGD SOR. FIG. 8C shows
a comparison of percent increase in SAGD cumulative oil.
[0023] While the present invention is susceptible to various
modifications and alternative forms, specific exemplary embodiments
thereof have been shown by way of example in the drawings and are
herein described in detail. It should be understood, however, that
the description herein of specific embodiments is not intended to
limit the invention to the particular forms disclosed, but on the
contrary, the intention is to cover all modifications, equivalents,
and alternatives falling within the spirit and scope of the
invention as defined by the appended claims.
DETAILED DESCRIPTION
[0024] The present invention relates generally to methods and
systems for enhancing hydrocarbon recovery through gas production
control for noncondensable solvents or gases in SAGD or ES-SAGD
operations.
[0025] In certain embodiments, a plurality of wells intersects a
low mobility reservoir. Steam may be injected into one or more
injection wells to heat the reservoir hydrocarbons and reduce their
viscosity so that hydrocarbons may be produced by way of one or
more production wells. The injection wells may be arranged and
paired with the production wells to form a SAGD process or where
solvents are used, an ES-SAGD process. A noncondensable gas may be
injected into one or more of the injection wells to beneficially
reduce the steam-to-oil ratio thus improving economic recovery.
Unfortunately, excessive production of noncondensable gases can
adversely suppress hydrocarbon production rates for reasons
explained further below. To counteract this problem, gas production
rates at the production wells may be controlled to optimize
hydrocarbon output by limiting the produced gas-to-water ratio
(GWR) to limited ranges, including ranges of about 1 to about
30.
[0026] In certain optional embodiments, the noncondensable gas may
comprise a gas from the combustion exhaust of a control device or
from a steam generator (e.g. flue gas). By taking advantage of
existing sources of flue gas, green house gases emissions may be
reduced by providing a useful application of existing flue gas
rather than venting the flue gas to the atmosphere.
[0027] Advantages of such enhanced hydrocarbon recovery processes
include, but are not limited to, higher production efficiencies,
lower steam-to-oil ratios, lower costs, a reduction of total
extraction time of in-situ hydrocarbons, and in some embodiments, a
reduction of greenhouse gas emissions.
[0028] Reference will now be made in detail to embodiments of the
invention, one or more examples of which are illustrated in the
accompanying drawings. Each example is provided by way of
explanation of the invention, not as a limitation of the invention.
It will be apparent to those skilled in the art that various
modifications and variations can be made in the present invention
without departing from the scope or spirit of the invention. For
instance, features illustrated or described as part of one
embodiment can be used on another embodiment to yield a still
further embodiment. Thus, it is intended that the present invention
cover such modifications and variations that come within the scope
of the invention.
[0029] FIG. 1 illustrates an example of an enhanced hydrocarbon
recovery system in accordance with one embodiment of the present
invention. Low mobility reservoir 115 is shown residing in
subterranean formation 110. Reservoir 115 suffers from low mobility
of the hydrocarbons therein due in part to high viscosity of the
hydrocarbons, low permeability, and/or low driving forces.
[0030] Injection well 120 and production well 125 both intersect
low mobility reservoir 115. Injection well 120 is provided for
introducing injected flow 121 into low mobility reservoir 115 by
way of injection well 120, whereas production well 125 is provided
for extracting production flow 126 by way of production well
125.
[0031] In this example, injection well 120 is superposed above
production well 125. Steam 137 is introduced into injection well
120. In this way, steam 137 enters low mobility reservoir 115,
heats the hydrocarbons therein to reduce their viscosity and so,
increases their mobility. The heated hydrocarbons flow under the
influence of gravity towards production well 125 along with any
condensed steam. The hydrocarbons and condensed steam are produced
by way of production flow 126 from production well 125. In this
way, a circulation pattern develops between injection well 120 and
production well 125, and a SAGD steam chamber develops around
injection well 120.
[0032] Because SAGD is an energy intensive process, any decrease in
the amount of steam that is used to produce a unit of hydrocarbons
is economically advantageous. The amount of steam used to generate
a corresponding amount of hydrocarbons is frequently measured by a
steam-to-oil ratio (SOR). This parameter is frequently used to
monitor the efficiency of oil production processes based on steam
injection. Another parameter that reflects the efficiency of
hydrocarbon recovery processes is the gas-to-water ratio (GWR),
which reflects the amount of noncondensable produced per unit of
water produced. Both a higher SOR and a higher GWR reflect higher
inefficiencies. Any improvement in these ratios is economically
desirable.
[0033] Unfortunately, excessive noncondensable gas production can
adversely affect hydrocarbon recovery. In particular, excessive
noncondensable gas production can decrease the relative
permeability of hydrocarbons near the production well and decrease
production.
[0034] Further, noncondensable gas, when injected at steam chamber
conditions, exhibits limited solubility in the fluids within the
steam chamber at these conditions. Slight changes in temperature
can have a substantial effect on the solubility of these
noncondensable gases and promote evolution of the noncondensable
gas back into the steam chamber. This results in lower temperatures
at the hydrocarbon drainage interface due to the partial pressure
effects of the noncondensable gas and impacts the rate at which oil
is produced. These noncondensable gases also tend to move towards
the production well thus increasing the gas saturation and
decreasing the permeability of hydrocarbons in the near production
well region. These factors can negatively impact performance and
adversely affect the economics of oil recovery.
[0035] Gas production rates may be controlled to optimize
efficiency of the process. In particular, production flow 126 may
be modulated to enhance hydrocarbon recovery by reducing the
produced gas-to-water ratio (GWR), leading to reduced steam-to-oil
ratios and consequently, higher efficiencies. The gas-to-water
ratio may be determined with reference to the ratio of the volume
fractions of gas and liquid from liquid/gas separator 140. In
certain embodiments, production flow 126 may be modulated by
production control valve 126 to achieve a gas-to-water ratio in the
production flow of about 1 to about 30, of about 1 to about 10, of
about 1 to about 5, of about 1 to about 2, of about 5 to about 10,
or any combination thereof. As will be further demonstrated below,
limiting the gas-to-water ratio to these ranges can significantly
improve production efficiencies.
[0036] Noncondensable gas 135 being injected into injection well
120 may comprise any gas that does not condense at any of the
reservoir temperature and pressure conditions. Examples of suitable
noncondensable gases include, but are not limited to, methane,
ethane, propane, butane, air, oxygen, nitrogen, hydrogen, carbon
dioxide, carbon monoxide, combustion gases from a control device or
other direct combustion device, combustion gases from a direct
steam generator, flue gas, or any combination thereof. In certain
embodiments, the amount of noncondensable gas that is introduced
varies and may include gas-to-water ratios from about 1 to about
1,000. In certain other embodiments, the gas-to-water ratio in the
injected flow varies from about 20 to about 100. The noncondensable
gas may comprise two or more noncondensable gases in some
embodiments.
[0037] In certain embodiments, solvent 139 may be introduced to
further enhance the efficiency of the hydrocarbon recovery process
by, for example, further reducing the viscosity of the low mobility
hydrocarbons. Example of suitable solvents include, but are not
limited to, carbon dioxide, an aliphatic hydrocarbon having 4
carbons to 30 carbons, a light non-condensable hydrocarbon solvent
having 1 to 4 carbons, naptha, Syncrude, diesel, an aromatic
solvent, toluene, benzene, xylene, hexane, or any combination
thereof.
[0038] It is recognized that the steam, solvents, or noncondensable
gases described herein may be introduced to the low mobility
reservoir continuously or intermittently, sequentially or combined,
or any combination thereof as desired.
[0039] FIG. 2 illustrates another example of an enhanced
hydrocarbon recovery system. In this example, steam generator 230
is shown generating steam 237 from water feed 231. A fuel source
233 such as natural gas and an oxidant 232 (e.g. air or oxygen) are
fed to direct steam generator 230 to provide the combustion heat
necessary to generate heat required to convert water feed 231 to
steam 237. As fuel source 233 is combusted, it converts to
combustion products, namely flue gas 235. Flue gas 235 may be
introduced to injection well 220 as a noncondensable gas similar to
noncondensable gas 135 depicted in FIG. 1. Here, however, using
flue gas 235 advantageously reduces green house gas emissions by
diverting flue gas 235 to a useful application.
[0040] Likewise, any other effluent from a control device or other
effluent from direct combustion device may be substituted for flue
gas 235 as desired. In certain embodiments, a fraction of fuel
source 233 may be combined with flue gas 235 to achieve optimal
compositions of injection flow 221. As before, flue gas 235
combines with steam 237 to form combined injection flow 221 which
is introduced into injection well 220. Hydrocarbons along with
condensed steam and any noncondensible gases are produced via
production well 225 to form combined production flow 226.
[0041] The process may be controlled to limit total production flow
226 to an amount that optimizes the gas-to-water ratio. One way of
achieving this control is illustrated by the control loop depicted
in FIG. 2. Gas meter 241 measures the flow rate of gas flow 241,
and liquid meter 242 measures the flow rate of liquid flow 242.
These flow rates may be converted to a ratio of volume fractions
and transmitted to controller 245 which modulates control valve 228
to achieve a desired gas-to-water ratio. By limiting total
production flow 226 to a desired gas-to-water ratio, more efficient
production of hydrocarbons may be realized.
[0042] In certain alternate embodiments, it is recognized that a
direct steam generator (DSG) could be substituted in place of steam
generator 230. Naturally, because direct steam generators output
the steam and flue gas as a single combined stream, in such a case,
steam 237 and noncondensable gas 235 would be combined into a
single output stream which would then be available for introducing
into wellbore 220. As in previous examples, it is recognized that a
solvent 239 could be optionally introduced into wellbore 220.
[0043] To facilitate a better understanding of the present
invention, the following examples of certain embodiments are given.
In no way should the following examples be read to limit, or
define, the scope of the invention.
Example
[0044] The following numerical simulations demonstrate the efficacy
of the methods described herein. Here, process simulations were
performed on a numerical simulator (i.e. CMG-STARS) to evaluate the
potential benefits of co-injecting a noncondensable gas, in this
case, butane, with steam for improving hydrocarbon recovery as
compared to steam injection processes.
[0045] An athbasca oil sands reservoir of 100 m in width by 30 m in
height by 850 m in length was used for the study. Two (850 m long)
horizontal wells were placed near the bottom, and in the middle, of
the reservoir and separated by 5 m in the vertical direction. The
lower horizontal well was placed I m above the bottom of the oil
bearing sands. Initially, a pre-heating period of 90 days was used
to heat the region between the wells by circulating steam in both
the injection and production wells (similar to field pre-heating
for SAGD).
[0046] A baseline case where steam-only was injected (SAGD) was
used for comparison with a steam-butane case where the butane gas
production rate was controlled and a steam-butane case where butane
gas production rate was uncontrolled. In all cases, a maximum
bottom hole injection pressure of 3.5 MPa was used. In the base
case, following pre-heating, steam was injected into the top well
and oil and water was produced from the bottom well. In the
steam-butane cases, following pre-heating, a mixture of
steam-butane at a volume fraction of 0.016 steam and 0.984 butane
gas was injected into the top well and oil, water and butane was
produced from the bottom well. The volume fraction was selected to
demonstrate the concept. However; other butane volume fractions
ranging from about 0.001 to about 0.999 may be used. The objective
of adding the butane to steam was to evaluate the potential for oil
production with less energy as compared to steam alone. The
injected gas would help in maintaining the reservoir pressure and
reduce oil viscosity and hence reduce steam energy
requirements.
[0047] The numerical simulator adjusted the total fluid injection
rate (steam in the case of SAGD and steam-gas in the case of butane
co-injection) to maintain the maximum injection bottom-hole
pressure at 3.5 MPa. FIG. 3 shows that the steam injection rate for
the SAGD process was the highest and for the steam-butane with
controlled gas production rate was the lowest. This data
illustrates a significant saving in steam requirements for the
controlled gas production case as compared to the SAGD process.
FIG. 4 illustrates that a maximum injection bottom-hole pressure of
3.5 MPa was practically maintained throughout the entire period of
injection, 5,000 days, for all three cases. After 5,000 days,
injection was stopped and production continued for all cases.
[0048] As described above, however, excessive production of
noncondensable gases may result in the suppression of hydrocarbon
production rate due to decreasing the relative permeability of oil
near the producer and limiting the production. Additionally,
excessive production of noncondensable gases may result in the
suppression of hydrocarbon production rate due to noncondensable
gases and light hydrocarbons, when injected at steam chamber
conditions; exhibit limited solubility in the fluids within the
steam chamber at these conditions. Therefore, slight changes in
temperature can have a substantial effect on the solubility of
these noncondensable gases and light hydrocarbons and promote
evolution of the co-injected gases back into the steam chamber.
This results in lower temperatures at the oil drainage interface
due to the partial pressure effects of the noncondensable gases and
impacting the rate at which oil is produced. Some gases also tend
to move towards the producer, thus, increasing the gas saturation
and decreasing the permeability of oil in the near production well
region. These can negatively impact performance and affect the
economics of oil recovery.
[0049] To address these problems, gas production rate at the
producer was controlled to optimize efficiency of the process. This
control limited the produced gas-to-water ratio (GWR) to a range of
about 1 to about 10. This control may be implemented in the field
via a control loop in conjunction with a gas/liquid meter and a
control valve installed on the production well at the surface. FIG.
5 illustrates a comparison between the controlled and uncontrolled
produced GWR. In the uncontrolled case, a produced GWR as high as
55 was obtained and this negatively impacted the performance of the
process. By using the gas production control concept, the process
performed at a significantly improved level as compared to SAGD and
the uncontrolled gas production rate cases.
[0050] FIG. 6 illustrates that at the end of the injection period,
5,000 days, the controlled gas production case produced more oil as
compared to SAGD and the uncontrolled gas production cases (613,649
m.sup.3 versus 542,410 m.sup.3 and 596,341 m.sup.3; respectively).
FIG. 7 illustrates that a cumulative steam-to-oil ratio (SOR) of
1.6 was obtained from the new concept as compared to 3.2 for SAGD
and 2.1 for the uncontrolled gas production case. This results in
significant improvement in energy efficiency and reduced water
requirement and greenhouse gas emissions by using the new concept.
In addition, FIG. 7 demonstrates that the improved thermal
efficiency is maintained throughout the life of the process, thus
improving the overall economics of recovery. Furthermore, FIG. 7
shows that if the processes was to be terminated at an economic SOR
of 2, then the SAGD process would be terminated after approximately
1,500 days and the uncontrolled gas production process after 5,000
days; however, the controlled gas production process would have
continued to produce for a much longer time than the other two
cases and much more oil would be produced before reaching the same
cut-off SOR of 2.
[0051] Table 1 below and FIG. 8 summarize the benefits of the
produced gas control concept as compared to SAGD and the
uncontrolled gas production cases.
TABLE-US-00001 TABLE 1 Summary of Performance Comparison
Uncontrolled Gas Controlled Gas SAGD Production Production
Cumulative oil (m.sup.3) 542,410 596,341 613,649 Percent recovery
(IOIP) 77 85 87 (%) Cumulative SOR 3.1 2.1 1.6 Percent increase in
-- 10 13 SAGD cumulative oil Percent reduction in -- 32 48 SAGD
SOR
[0052] The simulations were conducted using butane as the
non-condensable solvent however, other wide variety of
noncondensable gases and solvents maybe used. Suitable examples
include, but not limited to, methane, ethane, propane, butane, air,
oxygen, nitrogen, hydrogen, carbon dioxide, carbon monoxide,
combustion gases from a control device or other direct combustion
device, combustion gases from a direct steam generator, flue gas,
or any combination thereof. The flue gas may be obtained from any
industrial fuel burning installation for example, a steam
generator, a direct steam generator (DSG), or a combustion device.
In addition, the non-condensable additive was injected with the
steam in a continuous manner; however, an alternative injection
strategy may include injecting the additives intermittently or
sequentially with steam at different time intervals. Furthermore,
the concept maybe used in any steam injection processes including
SAGD and steam flooding.
[0053] It is recognized that any of the elements and features of
each of the devices described herein are capable of use with any of
the other devices described herein with no limitation. Furthermore,
it is explicitly recognized that the steps of the methods herein
may be performed in any order except unless explicitly stated
otherwise or inherently required otherwise by the particular
method.
[0054] Therefore, the present invention is well adapted to attain
the ends and advantages mentioned as well as those that are
inherent therein. The particular embodiments disclosed above are
illustrative only, as the present invention may be modified and
practiced in different but equivalent manners apparent to those
skilled in the art having the benefit of the teachings herein.
Furthermore, no limitations are intended to the details of
construction or design herein shown, other than as described in the
claims below. It is therefore evident that the particular
illustrative embodiments disclosed above may be altered or modified
and all such variations and equivalents are considered within the
scope and spirit of the present invention. Also, the terms in the
claims have their plain, ordinary meaning unless otherwise
explicitly and clearly defined by the patentee.
* * * * *