CA3046523C - System and method for sagd inter-well management and pseudo infill optimization scheme - Google Patents
System and method for sagd inter-well management and pseudo infill optimization scheme Download PDFInfo
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- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
- E21B43/2406—Steam assisted gravity drainage [SAGD]
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Abstract
Provided herein are systems and methods to implement a pseudo-infill well optimization process in a bitumen reservoir undergoing a gravity drainage method such as, for example, SAGD, expanding solvent (ES)-SAGD, or vapor extraction (VAPEX). The process can be implemented in a bitumen reservoir comprising a set of producer/injector well pairs, wherein each well pair is associated with a steam and/or solvent chamber, and the chambers have coalesced. The pseudo-infill well optimization process generally involves adjusting the injection and/or production rates of specific injector and/or producer wells, respectively, in the set to proactively manage inter well interactions. Such process can be used to reduce SORs, WORs and/or increase production rates on previously constrained wells.
Description
SYSTEM AND METHOD FOR SAGD INTER-WELL MANAGEMENT AND PSEUDO INFILL
OPTIMIZATION SCHEME
TECHNICAL FIELD
[0001] The following generally relates to a well management process for mitigating or eliminating well conformance and/or steam breakthrough issues in one or more wells.
BACKGROUND
OPTIMIZATION SCHEME
TECHNICAL FIELD
[0001] The following generally relates to a well management process for mitigating or eliminating well conformance and/or steam breakthrough issues in one or more wells.
BACKGROUND
[0002] Oil sands are a natural mix of sand, water, and bitumen. Bitumen is considerably viscous and does not flow like conventional crude oil. As such, bitumen is recovered from oil sands using either surface mining techniques or in situ techniques. In surface mining, overburden is removed to access the underlying bitumen reservoir, and the oil sands are transported to an extraction facility to separate the bitumen from the other components of the oil sands (i.e. tailings). For in situ techniques, the bitumen reservoir is heated and the bitumen within flows into one or more horizontal producer wells, leaving the formation rock in the bitumen reservoir in place. Both surface mining and in situ processes produce a bitumen product that is subsequently sent to an upgrading and refining facility, to be refined into one or more petroleum products.
[0003] Bitumen reservoirs that are too deep to feasibly permit bitumen recovery by mining techniques are typically accessed by drilling wellbores into the bitumen reservoir and implementing an in situ technology. There are various in situ technologies available that use steam, heated hydrocarbon solvent, or steam and solvent in combination to liberate the bitumen from the bitumen reservoir.
[0004] The most conventional in situ technique is Steam Assisted Gravity Drainage (SAGD), in which a pair of horizontally oriented wells are drilled into the bitumen reservoir, such that the pair of horizontal wells are vertically aligned with respect to each other and separated by a relatively small distance, typically in the order of several meters. The well installed closer to the surface and above the other well is generally referred to as an injector well, and the well positioned below the injector well is referred to as a producer well. The injector well and the producer well are then connected to various equipment installed at a surface site. The injector well facilitates steam injection into the reservoir. The injected steam propagates vertically and laterally into the reservoir to develop what is referred to as a steam chamber. Latent heat released by the injected steam mobilizes the bitumen by lowering its viscosity. The bitumen, in turn, drains due to gravity and is produced, along with condensed water, by the producer well.
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[0005] If existing SAGD injector and producer wells are not accessing an economic amount of bitumen in the reservoir, it can be desirable to drill what are known as infill wells between SAGD steam chambers. If done correctly, the addition of infill wells can both accelerate expected recovery and increase estimated ultimate recovery by improving the continuity between injector and producer wells. However, drilling infill wells can be considered costly, and if carried out incorrectly, this practice can make SAGD production less economic.
[0006] A parameter used to monitor the efficiency of oil production processes based on steam injection is the steam-oil ratio (SOR), which is a measure of the volume of steam required to produce one unit volume of oil. A significant portion of the total energy used in SAGD is directed toward steam generation, which is often fueled by natural gas combustion. Natural gas can be considered expensive, and its combustion generates greenhouse gas (GHG) emissions.
By decreasing the SOR, GHG emissions and operating costs per unit of produced oil can be decreased. However, challenges remain in avoiding steam breakthrough, i.e. the infiltration of injected steam directly into the producer well, which can increase SOR. Steam breakthrough can be difficult to avoid due to the relatively close distance between the injector well and the producer well.
By decreasing the SOR, GHG emissions and operating costs per unit of produced oil can be decreased. However, challenges remain in avoiding steam breakthrough, i.e. the infiltration of injected steam directly into the producer well, which can increase SOR. Steam breakthrough can be difficult to avoid due to the relatively close distance between the injector well and the producer well.
[0007] Furthermore, SOR can be difficult to control in a bitumen recovery operation being carried out in a reservoir having one or more thief zones such as a gas cap or water layer overlying a steam chamber. One method of avoiding steam loss to a gas cap is to operate the injector well such that the pressure of the associated steam chamber is not kept higher than the gas cap pressure. If the steam chamber pressure is kept higher than the gas cap pressure, steam and possibly some of the oil can be pushed into the gas cap. The steam can continuously condense as it moves upward into the gas cap, creating the need for additional flow of steam to replace the condensed steam, thereby increasing SOR.
[0008] Another parameter that can be indicative of the efficiency of a bitumen recovery process is the water-oil ratio (WOR), which refers to the ratio of produced water to produced oil.
Steam breakthrough, and an issue commonly known as water coning, can both increase WOR.
Many bitumen reservoirs undergoing SAGD have an active bottom water zone beneath the bitumen reservoir zone. When mobilized, bitumen in a SAGD process is pumped from a horizontal producer well completed in the bitumen reservoir zone, which can cause water to be drawn out of the bottom water zone in a conical shape. Eventually, water can encroach upon the horizontal producer well, where it is produced along with the bitumen, causing a steady increase in WOR. Throughput of downstream processing plants often decreases as WOR of 23673110.1 the produced fluid increases. This, in turn, can increase operating costs and reduce energy efficiency.
Steam breakthrough, and an issue commonly known as water coning, can both increase WOR.
Many bitumen reservoirs undergoing SAGD have an active bottom water zone beneath the bitumen reservoir zone. When mobilized, bitumen in a SAGD process is pumped from a horizontal producer well completed in the bitumen reservoir zone, which can cause water to be drawn out of the bottom water zone in a conical shape. Eventually, water can encroach upon the horizontal producer well, where it is produced along with the bitumen, causing a steady increase in WOR. Throughput of downstream processing plants often decreases as WOR of 23673110.1 the produced fluid increases. This, in turn, can increase operating costs and reduce energy efficiency.
[0009] It would be advantageous to develop a bitumen recovery technique that addresses at least one of the above-noted issues or disadvantages.
SUMMARY
SUMMARY
[0010] Provided herein are systems and methods to implement a pseudo-inf ill well optimization process in a bitumen reservoir undergoing a gravity drainage method such as, for example, SAGD, expanding solvent (ES)-SAGD, or vapor extraction (VAPEX). The bitumen reservoir in which the process is being implemented comprises a set of producer/injector well pairs. Each well pair is associated with a steam and/or solvent chamber, and the chambers have coalesced. The pseudo-infill well optimization process generally involves adjusting the injection and/or production rates of specific injector and/or producer wells, respectively, in the set to proactively manage inter well interactions. Such process can be used to reduce SORs, WORs and/or increase production rates on previously constrained wells.
[0011] In an aspect, there is provided a method of controlling an in situ process implemented in a bitumen reservoir, the bitumen reservoir comprising: a first injection chamber associated with a first injector well and a first producer well; a second injection chamber associated with a second injector well and a second producer well; the method comprising the steps of: a) operating the first and second injector wells at a normal injection rate to establish the first and second injection chambers and until the first and second injection chambers are in fluid communication with one another; b) increasing an injection rate at the first injector well and decreasing an injection rate at the second injector well and operating the injector wells for a first period of time; and c)decreasing the injection rate for the first injector well and increasing the injection rate at the second injector well and operating the injector wells for a second period of time.
[0012] In an implementation of the method, at step b), the first injector well is operated at an injection rate that is higher than the normal injection rate, and the second injector well is operated at an injection rate that is lower than the normal injection rate;
and at step c), the first injector well is operated at an injection rate that is lower than the normal injection rate, and the second injector well is operated at an injection rate that is higher than the normal injection rate.
and at step c), the first injector well is operated at an injection rate that is lower than the normal injection rate, and the second injector well is operated at an injection rate that is higher than the normal injection rate.
[0013] In another implementation of the method, the first injector well is at a higher elevation than the second injector well.
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[0014] .. In another aspect, provided is a method of controlling an in situ process implemented in a bitumen reservoir, the bitumen reservoir comprising: a first injection chamber associated with a first injector well and a first producer well; a second injection chamber associated with a second injector well and a second producer well; a third injection chamber associated with a third injector well and a third producer well; a fourth injection chamber associated with a fourth injector well and a fourth producer well; wherein the first, second, third and fourth injector wells form a set, the first and third injector wells being positioned as odd injector wells in the set, and the second and fourth injector wells being positioned as even injector wells in the set; the method comprising the steps of: a) operating the first, second, third, and fourth injector wells at a normal injection rate to establish the first and second injection chambers and until the first and second injection chambers are in fluid communication with one another; b) increasing an injection rate at the odd injector wells and decreasing an injection rate at the even injector wells and operating the injector wells for a first period of time; and c) decreasing the injection rate at the odd injector wells and increasing the injection rate at the even injector wells and operating the injector wells for a second period of time;
[0015] In an implementation of the method, at step b), the odd injector wells are operated at an injection rate that is higher than the normal rate, and the even injector wells are operated at an injection rate that is lower than the normal injection rate; and at step c), the odd injector wells are operated at an injection rate that is lower than the normal injection rate, and the even injector wells are operated at an injection rate that is higher than the normal injection rate.
[0016] In another implementation of the method, the odd injector wells are at higher elevations than the even injector wells.
[0017] .. In yet another implementation of the methods, 4D seismic data is used to determine when the injection chambers are in fluid communication with one another.
[0018] In yet another implementation of the methods, data from at least one observation well is used to determine when the injection chambers are in fluid communication with one another.
[0019] In yet another implementation of the methods provided is the further step of: d) repeating steps b) and c) until it is no longer economic to produce from the producer wells.
[0020] In yet another implementation of the methods, at least one key performance indicator (KPI) value is determined at regular intervals; and the at least one key performance indicator is associated with a performance value.
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[0021] In yet another implementation of the methods, the performance value is used to define the first and second time periods.
[0022] In yet another implementation of the methods, the injector wells are being operated at substantially the same injection rate prior to initiating the methods.
[0023] In yet another implementation of the methods the injector wells are injecting an injection fluid comprising steam.
[0024] In yet another implementation of the methods, the injection fluid further comprises at least one non-condensable gas.
[0025] In yet another implementation of the methods, the injection fluid further comprises at least one condensable gas.
[0026] In yet another implementation of the methods, the injector wells are injecting an injection fluid comprising at least one non-condensable gas.
[0027] In yet another implementation of the methods, the injector wells are injecting an injection fluid comprising at least one condensable gas.
[0028] In yet another implementation of the methods, the at least one KPI
is a water-oil ratio, a steam-oil ratio, a subcool and/or an oil production rate.
is a water-oil ratio, a steam-oil ratio, a subcool and/or an oil production rate.
[0029] In yet another aspect, provided is a method of controlling an in situ process implemented in a bitumen reservoir, the bitumen reservoir comprising: a first injection chamber associated with a first injector well and a first producer well; a second injection chamber associated with a second injector well and a second producer well, the second injector well being at a lower elevation than the first injector well; the method comprising the steps of: a) operating the first and second injector wells at a normal injection rate to establish the first and second injection chambers and until the first and second injection chambers are in fluid communication with one another; b) increasing an injection rate at the first injector well and decreasing an injection rate at the second injector well.
[0030] In an implementation of the method, at step b), the injection rate of the second injector well is decreased to a minimum injection rate to maintain the second injection chamber.
[0031] In yet another aspect, provided is a method of controlling an in situ process implemented in a bitumen reservoir, the bitumen reservoir comprising: a first injection chamber associated with a first injector well and a first producer well; a second injection chamber associated with a second injector well and a second producer well; a third injection chamber 23673110.1 associated with a third injector well and a third producer well; a fourth injection chamber associated with a fourth injector well and a fourth producer well; wherein the first, second, third and fourth injector wells form a set, the first and third injector wells being positioned as odd injector wells in the set, and the second and fourth injector wells being positioned as even injector wells in the set; the second injector well being at a lower elevation than the first injector well; the fourth injector well being at a lower elevation than the third injector well; the method comprising the steps of: a) operating the first, second, third, and fourth injector wells at a normal injection rate to establish the first and second injection chambers and until the first and second injection chambers are in fluid communication with one another; and b) increasing the injection rates at the odd injector wells and decreasing the injection rates at the even injector wells.
[0032] In an implementation of the method, the second injector well is at a lower elevation than the third injector well.
[0033] In another implementation of the method, at step b), the injection rates of the even injector wells are decreased to a minimum injection rate to maintain the second and fourth injection chambers.
[0034] In yet another implementation of the methods, at step b), the injector wells are operated for a first time period; and the method further comprises: increasing the injection rates at the even injector wells and decreasing the injection rates at the odd injector wells and operating for a second time period.
[0035] In yet another implementation of the methods, 4D seismic data is used to determine when the injection chambers are in fluid communication with one another.
[0036] In yet another implementation of the methods, data from at least one observation well is used to determine when the injection chambers are in fluid communication with one another.
[0037] In yet another implementation of the methods, provided is the further step of: d) repeating steps b) and c) until it is no longer economic to produce from the producer wells.
[0038] In yet another implementation of the methods, at least one KPI value is determined at regular intervals; and the at least one KPI value is associated with a performance value.
[0039] In yet another implementation of the methods, the performance value is used to define the first and second time periods.
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[0040] In yet another implementation of the methods, the injector wells are being operated at substantially the same injection rate prior to initiating the method.
[0041] In yet another implementation of the methods, the injector wells are injecting an injection fluid comprising steam.
[0042] In yet another implementation of the methods, the injector wells are injecting an injection fluid comprising steam.
[0043] In yet another implementation of the methods, the injection fluid further comprises at least one non-condensable gas.
[0044] In yet another implementation of the methods, the injection fluid further comprises at least one condensable gas.
[0045] In yet another implementation of the methods, the injector wells are injecting an injection fluid comprising at least one non-condensable gas.
[0046] In yet another implementation of the methods, the injector wells are injecting an injection fluid comprising at least one condensable gas.
[0047] In yet another implementation of the methods, the at least one KPI
is a water-oil ratio, a steam-oil ratio, a subcool and/or an oil production rate.
is a water-oil ratio, a steam-oil ratio, a subcool and/or an oil production rate.
[0048] In yet another implementation of the methods, the methods are applied to mitigate one or more of steam breakthrough, bottom water coning, and steam loss to thief zones.
[0049] In yet another implementation of the methods, the in situ process is SAGD.
[0050] In yet another aspect, provided is a system for carrying out the methods, the system comprising: a source of an injection fluid; at least one injection apparatus for injecting the injection fluid into the bitumen reservoir through the injector wells; and a control system for adjusting the injection rates.
[0051] In an implementation of the system, the control system comprises:
one or more observation wells for determining when the injection chambers are in fluid communication;
metering equipment for determining injection rates, water production rates and oil production rates; and temperature gauges for determining temperature values at the injector wells and the producer wells.
one or more observation wells for determining when the injection chambers are in fluid communication;
metering equipment for determining injection rates, water production rates and oil production rates; and temperature gauges for determining temperature values at the injector wells and the producer wells.
[0052] In another implementation of the system, the observation wells are used to acquire 4D seismic data to determine when the injection chambers are in fluid communication.
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[0053] In yet another implementation of the system, the injection fluid comprises steam.
[0054] In yet another implementation of the system, the injection fluid comprises a non-condensable gas.
[0055] In yet another implementation of the system, the injection fluid comprises a condensable gas.
[0056] In yet another implementation of the system, the control system uses the water production rates, oil production rates, and/or temperature values to determine KPI values.
[0057] In yet another implementation of the system, the KPI values are one or more of oil production rate, WOR, SOR and subcool.
[0058] In yet another implementation of the system, the control system associates the KPI
values with a performance value to define the time periods.
values with a performance value to define the time periods.
[0059] BRIEF DESCRIPTION OF THE DRAWINGS
[0060] Embodiments will now be described with reference to the appended drawings wherein:
[0061] FIG. 1 is a cross-sectional view of a SAGD system located in a bitumen reservoir.
[0062] FIG. 2 is a schematic cross-sectional view of a set of SAGD well pairs illustrating stages in a pseudo-infill well optimization process.
[0063] FIG. 3 is a flow chart illustrating a method for applying a pseudo-infill well process to optimize inter-well management.
[0064] FIG. 4 is a schematic cross-sectional view of a set of SAGD well pairs illustrating stages in a pseudo-infill well optimization process.
[0065] FIG. 5 is a flow chart illustrating a method for applying a pseudo-infill well process to optimize inter-well management.
[0066] FIG. 6 is a schematic cross-sectional view of a set of SAGD well pairs illustrating a pseudo-infill well optimization process.
[0067] FIG. 7A is a schematic cross-sectional view of a set of SAGD well pairs located in a bitumen reservoir wherein water from a bottom water zone is encroaching two producer wells.
[0068] FIG. 7B is a schematic cross-sectional view of a set of SAGD well pairs located in a bitumen reservoir wherein water coning is being mitigated.
23673110.1 DETAILED DESCRIPTION
23673110.1 DETAILED DESCRIPTION
[0069] In a gravity drainage operation wherein a set of one or more producer/injector well pairs are arranged in a bitumen reservoir such that the set of wells can interact with each other, inter-well interactions can be proactively managed to improve energy efficiency. Gravity drainage operations can utilize steam, heated hydrocarbon solvent, or steam and solvent in combination to liberate the bitumen from the bitumen reservoir.
[0070] In such a set of producer/injector well pairs, if adjacent steam or solvent chambers have coalesced, fluid communication can occur therebetween. By increasing and/or decreasing the injection rate of specific wells in the set, the flow of the steam and/or solvent between and within the respective steam chambers can be altered. It is believed that similar changes in injected fluid flow can be achieved in analogous solvent/water- and solvent-based gravity drainage processes such as, for example, ES-SAGD, and VAPEX, respectively.
[0071] Thus, while the principles discussed herein are explained within the context of a SAGD operation, it will be appreciated that the same principles can be applied to any gravity drainage operation involving a set of horizontal producer/injector well pairs situated in a bitumen reservoir, wherein each pair is associated with a steam and/or solvent chamber, and wherein the chambers have coalesced.
[0072] The above phenomenon may in some cases allow for the application of a "pseudo infill" process, wherein high and low steam injection rates in odd and even (or otherwise "alternating") injector wells are periodically alternated (or otherwise adjusted in an alternating fashion) after the steam chambers have coalesced. The expression "pseudo infill" is used to describe the process because the producer wells below the injectors operating at decreased injection rates essentially act as infill wells. In a pilot implementation of this process, lower SORs and WORs relative to standard SAGD (i.e., wherein equal amounts of steam are injected at each injector well), and increased production rates on previously constrained wells were achieved. Accordingly, it is postulated that altering the flow of steam between the chambers can mobilize bitumen unlikely to be produced via standard SAGD, thereby avoiding the need to drill potentially costly infill wells. Moreover, it is believed that improvements in SOR and WOR
can be attributed at least in part to the ability of the pseudo infill concept to mitigate issues such as steam breakthrough, bottom water coning and/or steam loss to thief zones (e.g., gas caps or water layers).
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can be attributed at least in part to the ability of the pseudo infill concept to mitigate issues such as steam breakthrough, bottom water coning and/or steam loss to thief zones (e.g., gas caps or water layers).
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[0073] As discussed in greater detail below, the pseudo infill concept can be implemented in a variety of configurations and is not limited to alternating increasing and decreasing steam injection rates of even and odd injector wells in a set.
[0074] Turning now to the figures, FIG. 1 illustrates a bitumen reservoir 180 such as that found in the Canadian oil sands, which is accessed for in situ bitumen recovery. The bitumen reservoir 180 typically includes a number of geological materials such as a rock matrix, sand, and one or more fluids such as the bitumen that is being targeted. In the example shown in FIG. 1, the bitumen reservoir 180 underlies a layer of overburden 170 between the bitumen reservoir 180 and the surface 160. In the implementation shown in FIG. 1, a producer well 120 and an injector well 110 are positioned within the bitumen reservoir 180.
[0075] In FIG 1, a bottom water zone 190 underlies the bitumen reservoir 180 and an underlying rock formation 195 at least partially underlies the bottom water zone 190.
[0076] In FIG. 2, a pseudo infill optimization process is schematically illustrated using a set of four adjacent SAGD producer/injector well pairs positioned in the bitumen reservoir 180. It can be appreciated that a set of four well pairs is shown for ease of illustration and the number of sets of well pairs should not be considered limiting.
[0077] The process includes three phases. In phase 200, adjacent injector wells 230, 240, 250 and 260 are operated at similar injection rates to form or otherwise contribute to steam chambers 235, 245, 255 and 265, respectively, such that each steam chamber 235, 245, 255, 265 overlaps with its immediately adjacent steam chamber(s). That is, in this example the steam chambers have coalesced. In phase 210, the steam injection rates at injector wells 230 and 250 (the "odd" wells in the particular sequence of wells shown in FIG. 2) can be increased while the steam injection rates at wells 240 and 260 (the "even" wells in the particular sequence of wells shown in FIG. 2) can be decreased. Adjusting the injection rates in this way can change the flow patterns of the injected steam, which can increase steam-oil contact in steam chambers 235, 245, 255 and 265. This can, in turn, decrease the SOR. When the SOR begins to exceed expected values and/or when steam breakthrough is observed, phase 220 can be initiated. In phase 220, the steam injection rate at wells 230 and 250 (i.e., the odd wells as defined above) can be decreased while the steam injection rate at wells 240 and 260 (i.e., the even wells as defined above) can be increased. As noted above, adjusting the injection rates can result in a change in the steam flow patterns between steam chambers 235, 245, 255, 265.
In phase 210, for example, the higher steam injection rate in chambers 235 and 255 relative to chambers 240 and 260 can cause some steam to flow from chambers 235 and 255 to flow into 23673110.1 chambers 245 and 265. This, in turn, can increase steam-oil contact and mobilize a larger portion of bitumen, thereby decreasing SOR. The alternating of phases 210 and 220 can occur a number of times based on the observed SOR and well conformance. The timing of such alternating and the extent by which injection rates are increased and decreased can be also be determined by considering measured values of other key performance indicators (KPIs) including, but not limited to oil production rates, WORs, and subcools.
In phase 210, for example, the higher steam injection rate in chambers 235 and 255 relative to chambers 240 and 260 can cause some steam to flow from chambers 235 and 255 to flow into 23673110.1 chambers 245 and 265. This, in turn, can increase steam-oil contact and mobilize a larger portion of bitumen, thereby decreasing SOR. The alternating of phases 210 and 220 can occur a number of times based on the observed SOR and well conformance. The timing of such alternating and the extent by which injection rates are increased and decreased can be also be determined by considering measured values of other key performance indicators (KPIs) including, but not limited to oil production rates, WORs, and subcools.
[0078] It can be appreciated that the above principles can be applied to a set of any two or more producer/injector well pairs in a SAGD process to improve energy efficiency and/or to increase production rates of previously constrained wells.
[0079] The flow chart shown in FIG. 3 illustrates a process wherein the energy efficiency of a SAGD process applied to the bitumen reservoir 180 can be improved by alternating between higher/lower injection rates of even/odd injector wells in a set of injector pairs. At step 300, the reservoir is assumed to be undergoing a standard SAGD process, e.g., as illustrated in stage 200 in FIG. 2. At step 310, seismic data (e.g., 4D seismic) and/or samples from observation wells can be assessed at regular intervals to determine if the steam chambers have coalesced.
If the steam chambers have coalesced, the process moves to step 320, wherein the injection rates at the odd injector wells 230, 250 are increased while the injection rates at the even injector wells 240, 260 are decreased. At step 320, the respective injection rates are adjusted based on information such as pilot operation data, reservoir simulation data, 4D seismic data, and/or observation well data. At step 330, KPIs such as SOR and WOR are continuously monitored. If measured values of KPIs suggest a decline in performance below threshold values, the injection rates at the odd injector wells 230, 250 can be decreased while the injection rates at the even injector wells 240, 260 can be increased, or vice-versa depending on the current relative injection rates, at step 340. This process then returns to step 320 and can continue until KPIs indicate that performance values are not meeting threshold values in any step.
If the steam chambers have coalesced, the process moves to step 320, wherein the injection rates at the odd injector wells 230, 250 are increased while the injection rates at the even injector wells 240, 260 are decreased. At step 320, the respective injection rates are adjusted based on information such as pilot operation data, reservoir simulation data, 4D seismic data, and/or observation well data. At step 330, KPIs such as SOR and WOR are continuously monitored. If measured values of KPIs suggest a decline in performance below threshold values, the injection rates at the odd injector wells 230, 250 can be decreased while the injection rates at the even injector wells 240, 260 can be increased, or vice-versa depending on the current relative injection rates, at step 340. This process then returns to step 320 and can continue until KPIs indicate that performance values are not meeting threshold values in any step.
[0080] In FIG. 4, another example of a pseudo-infill optimization process is schematically illustrated using a set of six adjacent SAGD producer/injector well pairs. As with the previous example, it can be appreciated that a set of six well pairs is shown for ease of illustration and the number of sets of well pairs should not be considered limiting. Moreover, although three phases are illustrated in FIG. 4, it will be understood that the process can be implemented using any number of phases. In phase 400, it can be seen that steam chambers 435, 445, 455, 465, 475 and 485 have coalesced. Moreover, injector wells 430 and 460 are operating at relatively 23673110.1 higher injection rates than injector wells 440, 450, 470 and 480. If target measurements or improvements in KPIs such as SOR and WOR relative to standard SAGD operation are observed, phase 400 can be maintained. If not, phase 410 can be initiated.
[0081] In phase 410, the steam injection rates at injector wells 430 and 460 can be decreased while the steam injection rates at wells 440 and 470 can be increased. The injection rates at injector wells 450 and 480 in this example remain constant. If target measurements or improvements in KPIs such as SOR and WOR relative to standard SAGD operation are observed, phase 410 can be maintained. If not, phase 420 can be initiated.
[0082] In phase 420, the steam injection rates at injector wells 440 and 470 can be decreased while the steam injection rates at wells 450 and 480 can be increased. The injection rates at injector wells 430 and 460 in this example remain constant. If target measurements or improvements in KPIs such as SOR and WOR relative to standard SAGD operation are observed, phase 420 can be maintained. Multiple iterations of this process, with each iteration involving different permutations of relatively higher/lower injection rates of the injector wells 430, 440, 450, 460, 470 and 480, can be employed to optimize SOR, WOR and increase overall production. It will be understood that 4D seismic and observation well data can be continuously monitored throughout the process shown in FIG. 4, in the conventional manner.
[0083] In view of the foregoing, it can be appreciated that the pseudo infill optimization process is not limited to alternating injection rates of even/odd injector wells. More generally, as discussed in greater detail with reference to FIG. 5, the process described herein can be applied to any set of SAGD producer/injector well pairs wherein the respective steam chambers are in fluid communication with one another (i.e. the chambers have coalesced). The fluid continuity between the coalesced chambers can enable operators to selectively inject and produce at specific locations. For example, steam injection can be increased in chambers situated at high elevations relative to others in a set, and that do not have an overlying gas cap, and reduced in chambers at lower elevations and having overlying gas caps. If necessary, and as is generally known, production can be decreased in the steam chamber wherein injection has been increased to further prevent bottom water influx into the producer well. Due to chamber continuity, the steam can continuously flow from the higher pressure and elevation chambers to the lower pressure and elevation chambers, wherein bitumen is mobilized and collected by the pseudo infill producer wells. Above the pseudo infill producer wells, injection can be maintained at the minimum rate necessary to maintain the associated steam chambers. The chambers surrounding such pseudo infill wells can be surrounded by geological features such as those 23673110.1 discussed above which could, in standard SAGD operation (i.e., wherein inter-well interactions are not being proactively managed), cause low productivity and overall energy efficiency.
[0084] The flow chart shown in FIG. 5 illustrates a process whereby the energy efficiency of a SAGD process in reservoir 180 can be improved by adjusting steam injection rates of certain injector wells in a set of injector wells, based on measured KPIs. At step 500, the reservoir is assumed to be undergoing a standard SAGD process. At step 510, seismic data and/or observation wells are assessed at regular time intervals to determine if the steam chambers have coalesced. If the steam chambers have coalesced, the process can move to step 520, wherein the injection rates at certain injector wells in the set are adjusted based on information such as pilot operation, reservoir simulation, 4D seismic, and/or observation well data. At step 530, KPIs such as SOR, oil production rates, and WOR are continuously monitored. If KPI
measurements suggest a decline in performance below threshold values, injection rates can be adjusted at step 550 and the process returns to step 530. If KPI measurements indicate acceptable or improved performance, the process moves to step 540 where operational parameters are maintained and the process returns to step 530 to continuously monitor KPIs.
This process can occur until KPIs indicate that performance values are not meeting threshold values in any step.
measurements suggest a decline in performance below threshold values, injection rates can be adjusted at step 550 and the process returns to step 530. If KPI measurements indicate acceptable or improved performance, the process moves to step 540 where operational parameters are maintained and the process returns to step 530 to continuously monitor KPIs.
This process can occur until KPIs indicate that performance values are not meeting threshold values in any step.
[0085] It is known that in SAGD processes, production is typically achieved predominately via the gravity drainage of bitumen. Accordingly, when implementing a pseudo-infill well optimization process in a set of well pairs forming interconnected steam chambers, the elevation of each well can be an important consideration. Increasing steam injection at injector wells at higher elevations in the set can facilitate the flow of steam and possibly oil from higher chambers to lower chambers. It is postulated that this can mobilize at least a portion of the bitumen inaccessible by a standard SAGD operation by changing the steam flow.
In other words, the same amount of steam can contact and mobilize a greater amount of bitumen.
In other words, the same amount of steam can contact and mobilize a greater amount of bitumen.
[0086] In the implementation illustrated in FIG. 6, injector wells 600 and 620 are located at a higher elevation when compared to injector wells 610, 630, 640 and 650. By increasing the injection rates of wells 600 and 620 as compared to injector wells 610, 630, 640 and 650, steam and possibly some heated bitumen can flow from chamber 605 to chamber 615.
Steam flowing from chamber 605 to 615 can further heat and mobilize bitumen in chamber 615 where it is collected by producer well 612. As mentioned, it is postulated that mobilized bitumen from chamber 605 can also be pushed into chamber 615, which is at a lower elevation than chamber 605, while it descends due to gravity and is subsequently collected by producer well 612. In a 23673110.1 similar manner, steam from injector 620 can flow from chamber 625 to chambers 615, 630, 640 and/or 650, thereby increasing the portion of bitumen mobilized in these lower chambers. This bitumen can be collected by gravity drainage by the producer wells 612, 632, 642 and/or 652. A
projected flow path of the steam originating at each of the injector wells is illustrated with arrows. The size of the arrows is intended to show the relative injection rates.
Steam flowing from chamber 605 to 615 can further heat and mobilize bitumen in chamber 615 where it is collected by producer well 612. As mentioned, it is postulated that mobilized bitumen from chamber 605 can also be pushed into chamber 615, which is at a lower elevation than chamber 605, while it descends due to gravity and is subsequently collected by producer well 612. In a 23673110.1 similar manner, steam from injector 620 can flow from chamber 625 to chambers 615, 630, 640 and/or 650, thereby increasing the portion of bitumen mobilized in these lower chambers. This bitumen can be collected by gravity drainage by the producer wells 612, 632, 642 and/or 652. A
projected flow path of the steam originating at each of the injector wells is illustrated with arrows. The size of the arrows is intended to show the relative injection rates.
[0087] As noted above, the principles discussed herein can be applied to mitigate issues such as water coning and steam loss to thief zones such as gas caps or water layers in bitumen or heavy oil production processes.
[0088] Water coning occurs when mobile bottom water (i.e. water underlying a bitumen reservoir) is drawn up through the bitumen reservoir and toward a producer well completed in the reservoir. If bottom-water influx develops, this indicates that the pressure in the water is larger than the pressure in the steam chamber, and steps must be taken to balance the pressures. Because it is typically not known to be possible to reduce the pressure in the water zone, the pressure in the steam chamber and producer well region should be increased. Such a pressure increase can be achieved by increasing the operating pressure of the steam chamber by increasing the steam injection rate and/or by reducing the production rate. Once the pressures of the bottom water and the steam chambers are relatively balanced, the water influx can cease.
[0089] Turning to FIGs 7A and 7B, if bitumen or high viscosity oil is pumped from a horizontal well completed in the bitumen reservoir 180, water from bottom water zone 190 can cone up to the producer wells 702, 712, 722 and/or 732 and inhibit production.
In FIG. 7A, standard SAGD is occurring using a series of adjacent injector wells 700, 710, 720 and 730 and their respective producer wells 702, 712, 722 and 732. Steam chambers 705, 715, 725 and 735 have coalesced. Water cones 740 and 770 extend from the water reservoir 190 into steam chambers 705 and 735, respectively. The encroachment of cones 740 and 770 on producer wells 702 and 732 can inhibit production, which can reduce oil cuts and increase water cuts until it is no longer economic to produce at producer wells 702 and/or 732.
In FIG. 7A, standard SAGD is occurring using a series of adjacent injector wells 700, 710, 720 and 730 and their respective producer wells 702, 712, 722 and 732. Steam chambers 705, 715, 725 and 735 have coalesced. Water cones 740 and 770 extend from the water reservoir 190 into steam chambers 705 and 735, respectively. The encroachment of cones 740 and 770 on producer wells 702 and 732 can inhibit production, which can reduce oil cuts and increase water cuts until it is no longer economic to produce at producer wells 702 and/or 732.
[0090] In the implementation shown in FIG. 7B, a pseudo-infill optimization process is implemented in reservoir 180 to increase production of oil located in areas where production was previously constrained by bottom water coning. Injection rates are increased at injector wells 700 and 730, and injection is decreased at injector wells 710 and 720 to balance steam chamber pressure and bottom water pressure. Production can optionally be reduced at producer wells 702 and 732 to further increase the pressure in steam chambers 705 and 735.
23673110.1 By balancing the pressures of steam chambers 705 and 735 and the bottom water in zone 190, the cones 740 and 770 can be stabilized. This, in turn, can prevent the watering out of producer wells 702 and 732. Furthermore, shortly after the injection rates are adjusted, steam chambers 705 and 735 are operating at a higher pressure than steam chambers 710 and 720, which can cause the flow of steam from chamber 705 into chambers 715 and/or 725, and from chamber 735 into chambers 725 and/or 715. The general direction of such flow is illustrated by the dashed line arrows in the figures. In this way, even though the steam injection rates of injector wells 710 and 720 are reduced, steam from injector wells 702 and 732 can mobilize bitumen in steam chambers 715 and 725, where the bitumen is subsequently produced by producer wells 712 and 722. It will be appreciated that the production rates of injector wells 712 and 722 can be increased since producer wells 712 and 722 are less susceptible to water coning. The overall production can increase using the above method, since a larger amount of bitumen in chambers 705, 715, 725 and 735 can be mobilized due to the change in steam flow.
Additionally, the limited production rates of producer wells 702 and 732 can be compensated by the increased production of producer wells 712 and 722. By mitigating bottom water coning, WOR can be decreased which can ultimately improve energy efficiency of the SAGD process as discussed above. In accordance with the processes discussed with respect to FIG. 5, alternation could occur between implementations 7A and 7B to continuously alter the flow of steam between the chambers 705, 715, 725 and 735 to increase oil production, while carefully monitoring KPI's and seismic, and particularly WOR to reduce or eliminate the encroachment of cones 740, 750, 760 and 770 on producers 702, 712, 722, and 732, respectively.
23673110.1 By balancing the pressures of steam chambers 705 and 735 and the bottom water in zone 190, the cones 740 and 770 can be stabilized. This, in turn, can prevent the watering out of producer wells 702 and 732. Furthermore, shortly after the injection rates are adjusted, steam chambers 705 and 735 are operating at a higher pressure than steam chambers 710 and 720, which can cause the flow of steam from chamber 705 into chambers 715 and/or 725, and from chamber 735 into chambers 725 and/or 715. The general direction of such flow is illustrated by the dashed line arrows in the figures. In this way, even though the steam injection rates of injector wells 710 and 720 are reduced, steam from injector wells 702 and 732 can mobilize bitumen in steam chambers 715 and 725, where the bitumen is subsequently produced by producer wells 712 and 722. It will be appreciated that the production rates of injector wells 712 and 722 can be increased since producer wells 712 and 722 are less susceptible to water coning. The overall production can increase using the above method, since a larger amount of bitumen in chambers 705, 715, 725 and 735 can be mobilized due to the change in steam flow.
Additionally, the limited production rates of producer wells 702 and 732 can be compensated by the increased production of producer wells 712 and 722. By mitigating bottom water coning, WOR can be decreased which can ultimately improve energy efficiency of the SAGD process as discussed above. In accordance with the processes discussed with respect to FIG. 5, alternation could occur between implementations 7A and 7B to continuously alter the flow of steam between the chambers 705, 715, 725 and 735 to increase oil production, while carefully monitoring KPI's and seismic, and particularly WOR to reduce or eliminate the encroachment of cones 740, 750, 760 and 770 on producers 702, 712, 722, and 732, respectively.
[0091] FIGS 7A and 7B serve to illustrate example operational decisions that may be considered while proactively managing inter well interactions between SAGD
well pairs. In another implementation, it may be that water layers, gas caps, shale layers and bottom water are all present. Challenges associated with such features can be mitigated by considering the subject geology prior to and during production and proactively managing inter-well interactions according to the methods provided.
well pairs. In another implementation, it may be that water layers, gas caps, shale layers and bottom water are all present. Challenges associated with such features can be mitigated by considering the subject geology prior to and during production and proactively managing inter-well interactions according to the methods provided.
[0092] The term "injection chamber" as used hereinafter will be understood to mean a "steam chamber", "solvent chamber" or a "steam and solvent chamber".
[0093] As noted above, although the above implementations are discussed with respect to a standard SAGD process wherein only steam is injected, the same principles can apply to other gravity drainage methods wherein solvent is injected alone or co-injected with steamõ thereby forming an injection chamber that comprises solvent or solvent and steam.
23673110.1
23673110.1
[0094] For example, the pseudo-infill optimization process can be applied to a set of interconnected producer/injector well pairs where the injector wells are co-injecting a solvent comprising condensable or non-condensable gases, and each of the injector wells is associated with an injection chamber. Such non-condensable gases can include natural gas, natural gas byproducts and nitrogen. A suitable condensable gas is soluble carbon dioxide, which is injected as a vapor and subsequently condenses when contacting bitumen, thereby decreasing the viscosity of the bitumen and forming a mixture of condensed gas and bitumen. This mixture then drains due to gravity and can be produced by producer wells in the same manner as a condensed steam and bitumen mixture is produced in SAGD.
[0095] For simplicity and clarity of illustration, where considered appropriate, reference numerals may be repeated among the figures to indicate corresponding or analogous elements.
In addition, numerous specific details are set forth in order to provide a thorough understanding of the examples described herein. However, it will be understood by those of ordinary skill in the art that the examples described herein may be practiced without these specific details. In other instances, well-known methods, procedures and components have not been described in detail so as not to obscure the examples described herein. Also, the description is not to be considered as limiting the scope of the examples described herein.
In addition, numerous specific details are set forth in order to provide a thorough understanding of the examples described herein. However, it will be understood by those of ordinary skill in the art that the examples described herein may be practiced without these specific details. In other instances, well-known methods, procedures and components have not been described in detail so as not to obscure the examples described herein. Also, the description is not to be considered as limiting the scope of the examples described herein.
[0096] The examples and corresponding diagrams used herein are for illustrative purposes only. Different configurations and terminology can be used without departing from the principles expressed herein. For instance, components and modules can be added, deleted, modified, or arranged with differing connections without departing from these principles.
[0097] The steps or operations in the flow charts and diagrams described herein are just for example. There may be many variations to these steps or operations without departing from the principles discussed above. For instance, the steps may be performed in a differing order, or steps may be added, deleted, or modified.
[0098] Although the above principles have been described with reference to certain specific examples, various modifications thereof will be apparent to those skilled in the art as outlined in the appended claims.
23673110.1
23673110.1
Claims (49)
1. A method of controlling an in situ process implemented in a bitumen reservoir, the bitumen reservoir comprising:
a first injection chamber associated with a first injector well and a first producer well;
a second injection chamber associated with a second injector well and a second producer well;
the method comprising the steps of:
a) operating the first and second injector wells at a normal injection rate to establish the first and second injection chambers and until the first and second injection chambers have coalesced;
b) increasing an injection rate at the first injector well and decreasing an injection rate at the second injector well and operating the injector wells for a first period of time; and c) decreasing the injection rate for the first injector well and increasing the injection rate at the second injector well and operating the injector wells for a second period of time.
a first injection chamber associated with a first injector well and a first producer well;
a second injection chamber associated with a second injector well and a second producer well;
the method comprising the steps of:
a) operating the first and second injector wells at a normal injection rate to establish the first and second injection chambers and until the first and second injection chambers have coalesced;
b) increasing an injection rate at the first injector well and decreasing an injection rate at the second injector well and operating the injector wells for a first period of time; and c) decreasing the injection rate for the first injector well and increasing the injection rate at the second injector well and operating the injector wells for a second period of time.
2. The method of claim 1, wherein at step b), the first injector well is operated at an injection rate that is higher than the normal injection rate, and the second injector well is operated at an injection rate that is lower than the normal injection rate;
and wherein at step c), the first injector well is operated at an injection rate that is lower than the normal injection rate, and the second injector well is operated at an injection rate that is higher than the normal injection rate.
and wherein at step c), the first injector well is operated at an injection rate that is lower than the normal injection rate, and the second injector well is operated at an injection rate that is higher than the normal injection rate.
3. The method of claim 1 or 2 wherein the first injector well is at a higher elevation than the second injector well.
4. A method of controlling an in situ process implemented in a bitumen reservoir, the bitumen reservoir comprising:
a first injection chamber associated with a first injector well and a first producer well;
a second injection chamber associated with a second injector well and a second producer well;
a third injection chamber associated with a third injector well and a third producer well;
CPST Doc: 317999.1 Date Recue/Date Received 2020-11-25 a fourth injection chamber associated with a fourth injector well and a fourth producer well;
wherein the first, second, third and fourth injector wells form a set, the first and third injector wells being positioned as odd injector wells in the set, and the second and fourth injector wells being positioned as even injector wells in the set;
the method comprising the steps of:
a) operating the first, second, third, and fourth injector wells at a normal injection rate to establish the first and second injection chambers and until the first and second injection chambers have coalesced;
b) increasing an injection rate at the odd injector wells and decreasing an injection rate at the even injector wells and operating the injector wells for a first period of time;
and c) decreasing the injection rate at the odd injector wells and increasing the injection rate at the even injector wells and operating the injector wells for a second period of time.
a first injection chamber associated with a first injector well and a first producer well;
a second injection chamber associated with a second injector well and a second producer well;
a third injection chamber associated with a third injector well and a third producer well;
CPST Doc: 317999.1 Date Recue/Date Received 2020-11-25 a fourth injection chamber associated with a fourth injector well and a fourth producer well;
wherein the first, second, third and fourth injector wells form a set, the first and third injector wells being positioned as odd injector wells in the set, and the second and fourth injector wells being positioned as even injector wells in the set;
the method comprising the steps of:
a) operating the first, second, third, and fourth injector wells at a normal injection rate to establish the first and second injection chambers and until the first and second injection chambers have coalesced;
b) increasing an injection rate at the odd injector wells and decreasing an injection rate at the even injector wells and operating the injector wells for a first period of time;
and c) decreasing the injection rate at the odd injector wells and increasing the injection rate at the even injector wells and operating the injector wells for a second period of time.
5. The method of claim 4, wherein at step b), the odd injector wells are operated at an injection rate that is higher than the normal rate, and the even injector wells are operated at an injection rate that is lower than the normal injection rate; and wherein at step c), the odd injector wells are operated at an injection rate that is lower than the normal injection rate, and the even injector wells are operated at an injection rate that is higher than the normal injection rate.
6. The method of claim 4 or 5 wherein the odd injector wells are at higher elevations than the even injector wells.
7. The method of any one of claims 1 to 6 wherein 4D seismic data is used to determine when the injection chambers are in fluid communication with one another.
8. The method of any one of claims 1 to 7 wherein data from at least one observation well is used to determine when the injection chambers are in fluid communication with one another.
9. The method of any one of claims 1 to 8 further comprising the step of:
d) repeating steps b) and c) until it is no longer economic to produce from the producer wells.
CPST Doc: 317999.1 Date Recue/Date Received 2020-11-25
d) repeating steps b) and c) until it is no longer economic to produce from the producer wells.
CPST Doc: 317999.1 Date Recue/Date Received 2020-11-25
10. The method of any one of claims 1 to 9 wherein at least one key performance indicator (KPI) value is determined at regular intervals; and the at least one key performance indicator is associated with a performance value.
11. The method of claim 10 wherein the performance value is used to define the first and second time periods.
12. The method of any one of claims 1 to 11, wherein the injector wells are being operated at substantially the same injection rate prior to initiating the method.
13. The method of any one of claims 1 to 12 wherein the in situ process is steam-assisted gravity drainage (SAGD).
14. The method of any one of claims 1 to 12 wherein the injector wells are injecting an injection fluid comprising steam.
15. The method of claim 14 wherein the injection fluid further comprises at least one non-condensable gas.
16. The method of claim 14 or 15 wherein the injection fluid further comprises at least one condensable gas.
17. The method of any one of claims 1 to 12 wherein the injector wells are injecting an injection fluid comprising at least one non-condensable gas.
18. The method of any one of claims 1 to 12 or 17 wherein the injector wells are injecting an injection fluid comprising at least one condensable gas.
19. The method of any one of claims 10 to 18 wherein the at least one KPI
is a water-oil ratio, a steam-oil ratio, a subcool and/or an oil production rate.
is a water-oil ratio, a steam-oil ratio, a subcool and/or an oil production rate.
20. A method of controlling an in situ process implemented in a bitumen reservoir, the bitumen reservoir comprising:
CPST Doc: 317999.1 Date Recue/Date Received 2020-11-25 a first injection chamber associated with a first injector well and a first producer well;
a second injection chamber associated with a second injector well and a second producer well, the second injector well being at a lower elevation than the first injector well;
the method comprising the steps of:
a) operating the first and second injector wells at a normal injection rate to establish the first and second injection chambers and until the first and second injection chambers have coalesced;
b) increasing an injection rate at the first injector well and decreasing an injection rate at the second injector well.
CPST Doc: 317999.1 Date Recue/Date Received 2020-11-25 a first injection chamber associated with a first injector well and a first producer well;
a second injection chamber associated with a second injector well and a second producer well, the second injector well being at a lower elevation than the first injector well;
the method comprising the steps of:
a) operating the first and second injector wells at a normal injection rate to establish the first and second injection chambers and until the first and second injection chambers have coalesced;
b) increasing an injection rate at the first injector well and decreasing an injection rate at the second injector well.
21. The method of claim 20 wherein at step b), the injection rate of the second injector well is decreased to a minimum injection rate to maintain the second injection chamber.
22. A method of controlling an in situ process implemented in a bitumen reservoir, the bitumen reservoir comprising:
a first injection chamber associated with a first injector well and a first producer well;
a second injection chamber associated with a second injector well and a second producer well;
a third injection chamber associated with a third injector well and a third producer well;
a fourth injection chamber associated with a fourth injector well and a fourth producer well;
wherein the first, second, third and fourth injector wells form a set, the first and third injector wells being positioned as odd injector wells in the set, and the second and fourth injector wells being positioned as even injector wells in the set;
the second injector well being at a lower elevation than the first injector well;
the fourth injector well being at a lower elevation than the third injector well;
the method comprising the steps of:
a) operating the first, second, third, and fourth injector wells at a normal injection rate to establish the first and second injection chambers and until the first and second injection chambers have coalesced; and b) increasing the injection rates at the odd injector wells and decreasing the injection rates at the even injector wells.
CPST Doc: 317999.1 Date Recue/Date Received 2020-11-25
a first injection chamber associated with a first injector well and a first producer well;
a second injection chamber associated with a second injector well and a second producer well;
a third injection chamber associated with a third injector well and a third producer well;
a fourth injection chamber associated with a fourth injector well and a fourth producer well;
wherein the first, second, third and fourth injector wells form a set, the first and third injector wells being positioned as odd injector wells in the set, and the second and fourth injector wells being positioned as even injector wells in the set;
the second injector well being at a lower elevation than the first injector well;
the fourth injector well being at a lower elevation than the third injector well;
the method comprising the steps of:
a) operating the first, second, third, and fourth injector wells at a normal injection rate to establish the first and second injection chambers and until the first and second injection chambers have coalesced; and b) increasing the injection rates at the odd injector wells and decreasing the injection rates at the even injector wells.
CPST Doc: 317999.1 Date Recue/Date Received 2020-11-25
23. The method of claim 22 wherein the second injector well is at a lower elevation than the third injector well.
24. The method of claim 22 or 23 wherein at step b), the injection rates of the even injector wells are decreased to a minimum injection rate to maintain the second and fourth injection chambers.
25. The method of any one of claims 22 to 24 wherein at step b), the injector wells are operated for a first time period;
the method further comprising:
c) increasing the injection rates at the even injector wells and decreasing the injection rates at the odd injector wells and operating for a second time period.
the method further comprising:
c) increasing the injection rates at the even injector wells and decreasing the injection rates at the odd injector wells and operating for a second time period.
26. The method of claim 20 or claim 21 wherein at step b), the injector wells are operated for a first time period;
the method further comprising:
c) increasing the injection rate at the second injector well and decreasing the injection rate at the first injector well and operating for a second time period.
the method further comprising:
c) increasing the injection rate at the second injector well and decreasing the injection rate at the first injector well and operating for a second time period.
27. The method of any one of claims 20 to 26 wherein 4D seismic data is used to determine when the injection chambers are in fluid communication with one another.
28. The method of any one of claims 20 to 27 wherein data from at least one observation well is used to determine when the injection chambers are in fluid communication with one another.
29. The method of claim 25 or claim 26, further comprising the step of:
d) repeating steps b) and c) until it is no longer economic to produce from the producer wells.
d) repeating steps b) and c) until it is no longer economic to produce from the producer wells.
30. The method of any one of claims 25 to 29 wherein at least one KPI value is determined at regular intervals; and the at least one KPI value is associated with a performance value.
CPST Doc: 317999.1 Date Recue/Date Received 2020-11-25
CPST Doc: 317999.1 Date Recue/Date Received 2020-11-25
31. The method of claim 30 wherein the performance value is used to define the first and second time periods.
32. The method of any one of claims 20 to 31, wherein the injector wells are being operated at substantially the same injection rate prior to initiating the method.
33. The method of any one of claims 20 to 32 wherein the in situ process is SAGD.
34. The method of any one of claims 19 to 33 wherein the injector wells are injecting an injection fluid comprising steam.
35. The method of claim 34 wherein the injection fluid further comprises at least one non-condensable gas.
36. The method of claim 34 or claim 35 wherein the injection fluid further comprises at least one condensable gas.
37. The method of any one of claims 20 to 32 wherein the injector wells are injecting an injection fluid comprising at least one non-condensable gas.
38. The method of any one of claims 20 to 32 or 37 wherein the injector wells are injecting an injection fluid comprising at least one condensable gas.
39. The method of any one of claims 30 to 38 wherein the at least one KPI
is a water-oil ratio, a steam-oil ratio, a subcool and/or an oil production rate.
is a water-oil ratio, a steam-oil ratio, a subcool and/or an oil production rate.
40. The method of any one of claims 10 to 19 or 31 to 39 wherein the method is applied to mitigate one or more of steam breakthrough, bottom water coning, and steam loss to thief zones.
41. A system for carrying out the method of any one of claims 1 to 6 or 25, the system comprising:
a source of an injection fluid;
CPST Doc: 317999.1 Date Recue/Date Received 2020-11-25 at least one injection apparatus for injecting the injection fluid into the bitumen reservoir through the injector wells; and a control system for adjusting the injection rates.
a source of an injection fluid;
CPST Doc: 317999.1 Date Recue/Date Received 2020-11-25 at least one injection apparatus for injecting the injection fluid into the bitumen reservoir through the injector wells; and a control system for adjusting the injection rates.
42. The system of claim 41 wherein the control system comprises: one or more observation wells for determining when the injection chambers are in fluid communication;
metering equipment for determining injection rates, water production rates and oil production rates; and temperature gauges for determining temperature values at the injector wells and the producer wells.
metering equipment for determining injection rates, water production rates and oil production rates; and temperature gauges for determining temperature values at the injector wells and the producer wells.
43. The system of claim 42 wherein the observation wells are used to acquire 4D seismic data to determine when the injection chambers are in fluid communication.
44. The system of any one of claims 41 to 43 wherein the injection fluid comprises steam.
45. The system of any one of claims 41 to 44 wherein the injection fluid comprises a non-condensable gas.
46. The system of any one of claims 41 to 45 wherein the injection fluid comprises a condensable gas.
47. The system of any one of claims 42 to 46 wherein the control system uses the water production rates, oil production rates, and/or temperature values to determine KPI values.
48. The system of claim 47 wherein the KPI values are one or more of oil production rate, WOR, SOR and subcool.
49. The system of claim 47 or claim 48 wherein the control system associates the KPI
values with a performance value to define the time periods.
CPST Doc: 317999.1 Date Recue/Date Received 2020-11-25
values with a performance value to define the time periods.
CPST Doc: 317999.1 Date Recue/Date Received 2020-11-25
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA3046523A CA3046523C (en) | 2019-06-14 | 2019-06-14 | System and method for sagd inter-well management and pseudo infill optimization scheme |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA3046523A CA3046523C (en) | 2019-06-14 | 2019-06-14 | System and method for sagd inter-well management and pseudo infill optimization scheme |
Publications (2)
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| CN112963128B (en) * | 2021-03-03 | 2023-01-10 | 中国石油天然气股份有限公司 | Method for reducing overflow of steam cavity and preventing water channeling from top to bottom in SAGD development process |
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