CA2911737C - Process and system for increasing mobility of a reservoir fluid in a hydrocarbon-bearing formation - Google Patents

Abstract

A process is provided for increasing overall mobility of reservoir fluid utilizing a well including a generally vertical segment extending from a surface, and a generally horizontal segment extending into the hydrocarbon-bearing formation. The process includes injecting a heating fluid through a tube that extends through the generally vertical segment and into the generally horizontal segment of the well, the heating fluid exiting the tube in the generally horizontal segment of the well and entering a casing, near a closed end thereof, through which the heating fluid is returned to the surface, and heating the heating fluid to transfer heat to casing and to thereby conduct heat to the hydrocarbon-bearing formation.

Description

PROCESS AND SYSTEM FOR INCREASING MOBILITY OF A RESERVOIR FLUID
IN A HYDROCARBON-BEARING FORMATION
Technical Field [0001] The present invention relates to the production of hydrocarbons such as heavy oils and bitumen from an underground reservoir by heating the reservoir to mobilize the hydrocarbons.
Background

[0002] Extensive deposits of viscous hydrocarbons exist around the world, including large deposits in the Northern Alberta oil sands that are not susceptible to standard oil well production technologies. One problem associated with producing hydrocarbons from such deposits is that the hydrocarbons are too viscous to flow at commercially relevant rates at the temperatures and pressures present in the reservoir.
For such reservoirs, thermal techniques may be used to heat the reservoir to mobilize the hydrocarbons and produce the heated, mobilized hydrocarbons from wells.
One such technique for utilizing a horizontal well for injecting heated fluids and producing hydrocarbons is described in U.S. Patent No. 4,116,275, which also describes some of the problems associated with the production of mobilized viscous hydrocarbons from horizontal wells.

[0003] One thermal method of recovering viscous hydrocarbons using spaced horizontal wells is known as steam-assisted gravity drainage (SAGD). SAGD
utilizes gravity in a process that relies on density difference of the mobile fluids to achieve a desirable vertical segregation within the reservoir. Various embodiments of the SAGD
process are described in Canadian Patent No. 1,304,287 and corresponding U.S.
Patent No. 4,344,485. In the SAGD process, pressurized steam is delivered through an upper, horizontal, injection well into a viscous hydrocarbon reservoir while hydrocarbons are produced from a lower, parallel, horizontal, production well that is vertically spaced and near the injection well. The injection and production wells are generally situated in the lower portion of the reservoir, with the producer or production well located close to the base of the hydrocarbon deposit to collect the hydrocarbons that flow toward the bottom.

[0004] The SAGD process is believed to work as follows. The injected steam initially mobilizes the hydrocarbons to create a steam chamber in the reservoir around and above the horizontal injection well. The term steam chamber is utilized to refer to the volume of the reservoir that is saturated with injected steam and from which mobilized oil has at least partially drained. As the steam chamber expands, viscous hydrocarbons in the reservoir are heated and mobilized and move with aqueous condensate, under the effect of gravity, toward the bottom of the steam chamber, where the viscous hydrocarbons and aqueous condensate accumulate such that the liquid /
vapour interface is located below the steam injector and above the production well. The heated hydrocarbons and aqueous condensate are collected and produced from the production well.

[0005] To begin the production of hydrocarbons, the reservoir is preheated in a start-up operation by the circulation of steam and water at high pressure in the injection well or the production well or both the injection and the production well.
High pressure ensures that the condensed steam overcomes gravity and is returned to the surface.
The high pressure injection of steam, however, leads to inefficient heat exchange, for example, as a result of localized heating. Steam is generally more mobile than the viscous hydrocarbons and other fluids. Steam and water develop flow paths and these flow paths are favored by the steam injected and the condensed water, reducing the effectiveness of the steam in heating other regions in the reservoir.
Consequently, the steam chamber grows irregularly.

[0006] In addition mobile fluid zones that have relatively low bitumen saturation may exist near the reservoir. For example, the mobile fluid zones may have significant saturations of gas, water, or both. In such deposits, these mobile fluid zones can act as "thief zones" and have undesirable effects on recovery methods. For example, oil sands deposits may have a mobile fluid zone above the bitumen or heavy oils.
In such deposits, the mobile fluid zone can have a significant saturation of water or gas which acts as the "thief zone" and when injecting steam, steam at a pressure that is higher than the pressure in the water or gas zone may cause the flow of steam into the thief zone, resulting in steam loss. As the steam chamber approaches a gas zone, and if the steam pressure is kept higher than the gas zone pressure, steam and possibly some of the oil may be pushed into the gas zone. When the steam chamber contacts and is in communication with a "thief zone", significant heat loss to the "thief zone"
may also occur. For a water zone, steam and heat loss to the water zone, also referred to as a lean zone, may also occur.

[0007] Improvements in increasing hydrocarbon mobility are desirable.
Summary

[0008] According to an aspect of an embodiment, a process is provided for increasing overall mobility of reservoir fluid utilizing a well including a generally vertical segment extending from a surface, and a generally horizontal segment extending into a hydrocarbon-bearing formation. The process includes injecting a heating fluid through a tube that extends through the generally vertical segment and into the generally horizontal segment of the well, the heating fluid exiting the tube in the generally horizontal segment of the well and entering a casing, near a closed end thereof, through which the heating fluid is returned to the surface, the casing being closed to isolate the heating fluid from the hydrocarbon-bearing formation, and heating the heating fluid to transfer heat to casing and to thereby conduct heat to the hydrocarbon-bearing formation.

[0009] According to another aspect of an embodiment, a process is provided for increasing overall mobility of reservoir fluid utilizing a well including a generally vertical segment extending from a surface, and a generally horizontal segment extending into a hydrocarbon-bearing formation. The process includes inserting a casing having a generally closed end into the well such that the casing extends through the generally vertical segment, from a surface, and into the generally horizontal segment of the well, inserting a tube into the casing, the tube extending through the generally vertical segment and into the generally horizontal segment of the well, and injecting a heating fluid through the tube, the heating fluid exiting the tube in the generally horizontal segment of the well and entering the casing, the casing being closed to isolate the heating fluid from the hydrocarbon-bearing formation, such that the heating fluid returns to the surface.

[0010] According to another aspect of an embodiment, a system is provided for increasing overall mobility of reservoir fluid utilizing a well including a generally vertical segment and a generally horizontal segment extending into a hydrocarbon-bearing formation. The system includes a casing extending through the generally vertical segment and into the generally horizontal segment of the well, and a tube extending through the casing, through the generally vertical segment and into and through the generally horizontal segment of the well, the tube including an opening to facilitate the flow of the heating fluid from the tube and into the casing through which the heating fluid is returned to the surface, wherein the casing is closed to isolate the heating fluid from the hydrocarbon-bearing formation.
Brief Description of the Drawings

[0011] Embodiments of the present invention will be described, by way of example, with reference to the drawings and to the following description, in which:

[0012] FIG. 1 is a sectional view through a hydrocarbon-bearing formation, illustrating a SAGD well pair;

[0013] FIG. 2 is a sectional side view illustrating an injection and a production well pair;

[0014] FIG. 3 is a sectional side view illustrating a well according to an embodiment;

[0015] FIG. 4 is a flowchart illustrating a process of increasing hydrocarbon mobility in a hydrocarbon-bearing formation;

[0016] FIG. 5 is a sectional side view illustrating a well according to another embodiment;

[0017] FIG. 6 is a sectional side view illustrating a well according to yet another embodiment;

[0018] FIG. 7 is a sectional side view illustrating a well according to still another embodiment;

[0019] FIG. 8 is a graphical representation of oil saturation of a simulated hydrocarbon-bearing formation;

[0020] FIG. 9 is a graph illustrating cumulative oil (m3) recovered over a period of 2920 days for each of three examples;

[0021] FIG. 10 is a graph illustrating cumulative steam to oil ratio over a period of 2920 days for each of three examples;

[0022] FIG. 11 illustrates steam conformance within a hydrocarbon-bearing formation after 18 months of hydrocarbon production for a SAGD well pair after high pressure hot oil circulation in accordance with an example of an embodiment;

[0023] FIG. 12 illustrates steam conformance within a hydrocarbon-bearing formation after 18 months of hydrocarbon production for a SAGD well pair after high pressure steam circulation in accordance with an example of an embodiment;

[0024] FIG. 13 illustrates steam conformance within a hydrocarbon-bearing formation after 18 months of hydrocarbon production for a SAGD well pair after high pressure steam circulation open to the hydrocarbon-bearing formation;

[0025] FIG. 14 is a graph illustrating injection wellbore and production wellbore temperature ( C) measured over a period of 200 days;

[0026] FIG. 15 is a graph illustrating predicted and measured observation well temperature ( C) over a period of 200 days;

[0027] FIG. 16 is a graph illustrating predicted and actual inter-well temperature ( C) measured over a period of 4 months;

[0028] FIG. 17 illustrates a simulated hydrocarbon-bearing formation temperature distribution profile; and

[0029] FIG. 18 is a graph illustrating daily oil production rate (m3/d) over a period of 2920 days for each of three examples.
Detailed Description

[0030] For simplicity and clarity of illustration, reference numerals may be repeated among the figures to indicate corresponding or analogous elements.
Numerous details are set forth to provide an understanding of the examples described herein. The examples may be practiced without these details. In other instances, well-known methods, procedures, and components are not described in detail to avoid obscuring the examples described. The description is not to be considered as limited to the scope of the examples described herein.

[0031] The disclosure generally relates to a system and process for increasing overall mobility of reservoir fluid utilizing a well including a generally vertical segment extending from a surface, and a generally horizontal segment extending into a hydrocarbon-bearing formation. Start-up typically involves mobilizing viscous hydrocarbons in the reservoir to form a reservoir fluid and removing the reservoir fluid to create a porous pathway between the wells. As referred to above, viscous hydrocarbons may be mobilized by heating such as by injecting pressurized steam or hot water through the injection well or the production well. In some cases, the start-up process involves injecting steam and producing returned fluids from both the injection and production wells. According to an aspect of the present invention, the process includes injecting a heating fluid through a tube that extends through the generally vertical segment and into the generally horizontal segment of the well, the heating fluid exiting the tube in the generally horizontal segment of the well and entering a casing, near a closed end thereof, through which the heating fluid is returned to the surface, the casing being closed to isolate the heating fluid from the hydrocarbon-bearing formation, and heating the heating fluid to transfer heat to casing and to thereby conduct heat to the hydrocarbon-bearing formation.

[0032] Throughout the description, reference is made to an injection well and a production well. The injection well and the production well may be physically separate wells. Alternatively, the production well and the injection well may be housed, at least partially, in a single physical wellbore, for example, a multilateral well.
The production well and the injection well may be functionally independent components that are hydraulically isolated from each other, and housed within a single physical wellbore.
The isolation of heating fluid from the hydrocarbon-bearing formation, also referred to as a hydrocarbon reservoir or a reservoir, which facilitates the use of relatively high pressure and temperature is not limited to SAGD injection and production wells. The system and process may also be applied to other wells, such as single well SAGD, or a well that is disposed intermediate well pairs or adjacent to a well pair, also referred to as an infill well or a well drilled using Wedge WeIITM technology.

[0033] As described above, a steam assisted gravity drainage (SAGD) process may be utilized for mobilizing viscous hydrocarbons. In the SAGD process, a well pair, including a hydrocarbon production well and a steam injection well are utilized. One example of a well pair is illustrated in FIG. 1 and an example of a hydrocarbon production well 100 and an injection well 108 is illustrated in FIG. 2. The hydrocarbon production well 100 includes a generally vertical segment 102 and a generally horizontal segment 104 that extends near the base or bottom of the hydrocarbon reservoir 106.
The injection well 108 also includes a generally vertical segment 110 and a generally horizontal segment 112 that is disposed generally parallel to and is spaced vertically above the horizontal segment 104 of the hydrocarbon production well 100.

[0034] As referred to above, to increase mobility of hydrocarbons in a reservoir for hydrocarbon recovery utilizing a SAGD well pair or a single well that is disposed intermediate well pairs, also referred to as an infill well or a well drilled using Wedge WeIITM technology, high pressure steam directed into a well for pre-heating may cause non-uniform heating, or heat or steam loss to a "thief zone", or a combination of such problems.

[0035] A sectional side view of an example of a production well 300 is shown in FIG. 3. As shown in FIG. 3, the production well 300 includes the generally vertical segment 102 and the generally horizontal segment 104 that are joined at a heel 306 of the production well 300. The production well 300 includes an outer casing 308 that extends from the surface through the generally vertical segment 102 of the production well 300, through the heel 306 and to the generally horizontal segment 104. A
liner 310 is coupled to the outer casing 308 and extends along the generally horizontal segment 104 of the production well 300.

[0036] A heating fluid casing 312 is inserted into the production well 300 and extends inside the outer casing 308 and inside the liner 310 such that the heating fluid casing 312 extends through the generally vertical segment 102 and through the generally horizontal segment 104. The heating fluid casing 312 is closed along the length of the casing 312 and is closed at the downhole end 314 to isolate the interior of the heating fluid casing 312 from a remainder of the interior of the liner 310 and the outer casing 308.

[0037] A heating fluid tube 316 is inserted into the heating fluid casing 312 such that the heating fluid tube 316 extends through the generally vertical segment 102 and the generally horizontal segment 104 of the production well 300. The heating fluid tube 316 is open at an end 318 thereof for the flow of heating fluid through the heating fluid tube 316, out the end 318, and into the heating fluid casing 312. The heating fluid tube 316 may be insulated, for example, utilizing vacuum insulated tubing, or tubing insulated with any other suitable material, such as, inert gas, to retain heat while travelling through the heating fluid tube 316. The heating fluid is injected through the heating fluid tube 316 and is returned to the surface through the heating fluid casing 312.

[0038] The temperature in the generally horizontal segment 104 of the production well 300 may be monitored utilizing, for example, a distributed temperature sensing system (DTS) or array temperature sensing system (ATS) 320 that extends through the hydrocarbon production well 300 to obtain a real-time temperature profile across the generally horizontal segment 104 of the hydrocarbon production well 300. An may be, for example, a downhole fiber optic temperature sensor disposed in the well and extending along the length of the generally horizontal segment 104. The DTS or ATS 320 is utilized to sense the temperature along the length of the generally horizontal segment 104 to obtain a real-time temperature profile across the generally horizontal segment 104 of the production well 300.

[0039] The pressure in the production well 300 may also be monitored utilizing a pressure sensor 322 such as a bubble tube liquid level measurement system.
Alternatively, the DTS may also be utilized to detect pressure. Other pressure sensing apparatuses may also be successfully implemented, such as a piezometer or quartz gauges.

[0040] In the example illustrated in FIG. 3, a fluid tank 324, a pump 326, and a line heater 328 are utilized above ground for the circulation of fluid, such as water. The fluid from the fluid tank 324 is pressurized and heated above ground utilizing the pump 326 and the line heater 328. The pressurized and heated fluid is injected into the heating fluid tube 316 and exits the heating fluid tube 316 out the end 318, into heating fluid casing 312. The heating fluid is returned to the surface, to the fluid tank 324, via the heating fluid casing 312.

[0041] The Example of FIG. 3 is suitable for the high pressure circulation of steam closed from the reservoir. Alternatively, rather than utilizing a fluid tank 324, a pump 326, and a line heater 328, hot oil from a hot oil unit can be circulated at high pressure and closed from the reservoir.

[0042] Because the heating fluid is circulated in a closed loop in which the heating fluid is hydraulically isolated from the reservoir, the heating fluid may be circulated under very high temperature and pressure. In one example, the heating fluid is subsaturated water at a temperature, for example, of from about 200 C to about 400 C. Alternatively, the heating fluid may be any suitable oil, including, for example, bitumen, heavy oil, or produced emulsion from about 400 C to about 600 C.

[0043] Utilizing the fluid tank 324, the pump 326 and the line heater 328, heating fluid circulation in the production well 300 may begin when the production well 300 is completed with the heating fluid casing 312 and the heating fluid tube 316, and prior to completion of well facilities that may be utilized for steam generation and injection into the injection well.

[0044] A flowchart illustrating a process for increasing hydrocarbon mobility in a hydrocarbon-bearing formation is shown in FIG. 4. The process is carried out prior to hydrocarbon production from a viscous hydrocarbon reservoir, such as the reservoir 106. For the purpose of the present explanation, the process is described with continued reference to the examples of FIG. 1, FIG. 2, and FIG. 3. The process may contain additional or fewer processes than shown or described, and may be performed in a different order.

[0045] The flowchart shown in FIG. 4 begins after completing the well, including inserting the heating fluid casing 312 into the outer casing 308 and through the liner 310, and inserting the heating fluid tube 316 into the heating fluid casing 312.

[0046] Fluid, such as water, oil or bitumen, glycol, or a Duratherm TM
heat transfer fluid, is injected at 402 under pressure into the heating fluid tube 316. The heating fluid is injected at a pressure sufficient to reach a downhole pressure of, for example, about 2 MPa to about 30 MPa. The heating fluid is injected at a temperature of about to about 600 C, depending on the heating fluid utilized.

[0047] Thus, the heating fluid is injected at high pressure compared to known start-up processes. The heating fluid casing 312 hydraulically isolates the heating fluid from the reservoir.

[0048] The heating fluid may be heated prior to injection, for example, by the line heater 328 illustrated in FIG. 3 or may be heated subsurface or downhole, as described below with reference to FIG. 6. Because the heating fluid is under pressure, water, for example, can be subsaturated, facilitating heating without flashing to steam.

[0049] As the heating fluid travels through the heating fluid tube 316 and the heating fluid casing 312, the temperature in the region of the reservoir around the generally horizontal segment 104 rises as a result of conduction because the heating fluid is at a temperature that is well above the ambient temperature in the reservoir.

[0050] Because the heating fluid is under pressure, the heating fluid is forced out of the heating fluid tube 316, into the heating fluid casing 312 and flows toward the wellhead as more heating fluid is injected into the heating fluid tube 316.
The heating fluid is received at the wellhead at 404 and is recirculated.

[0051] The temperature or other conditions in the generally horizontal segment 104 of the production well 300 is monitored at 406. For example, the temperature may be monitored utilizing the array temperature sensing system (ATS) 320 that extends through the hydrocarbon production well 300 to obtain a real-time temperature profile across the generally horizontal segment 104 of the hydrocarbon production well 300.

[0052] When the temperature is not raised sufficiently to meet a threshold temperature at 408, the circulation of fluid at 402 and 404 continues. When the well conditions meet a threshold at 408, the process continues at 410. For example, based on a lowest-measured temperature along the length of the generally horizontal segment 104, as measured by the ATS, a temperature at a location of about 2.5 m to about 3 m distance away in the reservoir may be calculated. When the temperature at this location of about 2.5 m to about 3 m distance away in the reservoir is raised such that the temperature meets a threshold temperature, the process continues at 410.
Alternatively, a highest measured temperature, an average measured temperature, or a measured temperature at a specific location may be utilized to calculate a temperature at a location in the reservoir and the calculated temperature is compared to the threshold to determine when the process continues at 410. The circulation of heating fluid at 402 and 404 may continue, for example, for about 3 months to about 6 months.
The circulation of heating fluid at 402 and 404 may continue until a target temperature of, for example, about 80 C in the reservoir is reached.

[0053] Heating fluid injection is discontinued at 410. The heating fluid tube 316 and heating fluid casing 312 may be removed from the well prior to starting hydrocarbon production such that heating fluid is not circulated during hydrocarbon production.
Optionally, a further start-up process may be implemented between 410 and 412.
For example, after steam closed circulation, referred to herein as Steam CC, in which steam is isolated from the reservoir at 402, 404, 406, and 408, the injection well, the production well, or both the injection well and the production well may be re-completed or re-configured for a period of Steam Circulation, in which steam is not closed from the reservoir, prior to commencing hydrocarbon production at 412. A person of ordinary skill in the art is aware of various techniques for start-up processes, such as, for example, hot fluid wellbore circulation, the use of selected solvents such as xylene, as, for example, described in Canadian patent number 2,698,898 to Pugh, etal., the application of geomechanical techniques such as dilation, as, for example, described in Canadian patent number 2,757,125 to Abbate, etal., or the use of one or more microorganisms to increase overall fluid mobility in a near-wellbore region in an oil sands reservoir, as, for example, described in Canadian patent application number 2,831,928 to Bracho Dominguez, et al.. Such techniques may also be utilized in combination with the present system and method for start-up.

[0054] Hydrocarbon production is started at 412. During SAGD, steam is injected into an injection well to mobilize the hydrocarbons and grow the steam chamber in the reservoir, around and above the generally horizontal segment 112 of the injection well.
In addition to steam injection into the injection well, light hydrocarbons, such as C3 through C10 alkanes, either individually or in combination, may optionally be injected with the steam such that the light hydrocarbons function as solvents in aiding the mobilization of the hydrocarbons. The volume of light hydrocarbons that are injected is relatively small compared to the volume of steam injected. The addition of light hydrocarbons is referred to as a solvent aided process (SAP). Alternatively, or in addition to the light hydrocarbons, one or more surfactants may optionally be injected with the steam, as, for example, described in Canadian patent number 2,791,492 to Zeidani and Gupta. The addition of surfactant may be referred to as a surfactant-steam process. Alternatively, or in addition to SAP or a surfactant-steam process, various non-condensing gases, such as methane or carbon dioxide, may be injected.
Viscous hydrocarbons in the reservoir are heated and mobilized and the mobilized hydrocarbons drain under the effect of gravity. Fluids, including the mobilized hydrocarbons along with aqueous condensate, are collected in the generally horizontal segment 104. The fluids may also include water that was initially present in the reservoir, gases such as steam, production gases from the SAGD process, or a combination thereof.

[0055] Although the process of FIG. 4 is described above with reference to a production well, the process may also be carried out utilizing an injection well in which a heating fluid casing is inserted into an outer casing and through a liner, and a heating fluid tube is inserted into the heating fluid casing. Thus, the process may be carried out in both injection and production wells or in a single one of the wells.
Alternatively, the process may be carried out in a well that is disposed intermediate well pairs or adjacent to a well pair.

[0056] Thus, heating fluid is circulated in a closed loop in which the heating fluid is hydraulically isolated from the reservoir. The heating fluid may be circulated under very high temperature and pressure compared to typical temperatures and pressures utilized for start-up of, for example, a SAGD operation.

[0057] Rather than utilizing a slotted liner 310 in the generally horizontal segment of the well and a heating fluid casing 312 within the slotted liner to close off the circulating high pressure heating fluid from the reservoir, a closed outer casing may be utilized to the toe of the well. The heating fluid tube may extend inside the closed casing. When circulation of high pressure heating fluid is complete, the closed outer casing is perforated to provide openings to begin production or to commence steam injection in the injection well. Thus, a single casing may be utilized rather than the use of both a slotted liner and a closed casing within the slotted liner.

[0058] A sectional side view of another example of a well 500 is shown in FIG. 5.
The well 500 may be, for example, a production well of a well pair.
Alternatively, or additionally, the well 500 may be an injection well. Alternatively, the well may be a well that is disposed intermediate well pairs or adjacent to a well pair, also referred to as an infill well or a well drilled using Wedge WeIITM technology. The well 500 includes the generally vertical segment and the generally horizontal segment that are joined at a heel of the well 500. The well 500 includes an outer casing 508 that extends from the surface through the generally vertical segment of the well 500, through the heel and to the generally horizontal segment. A liner 510 is coupled to the outer casing 508 and extends along the generally horizontal segment of the well 500.

[0059] A heating fluid casing 512 is inserted into the well 500 and extends inside the outer casing 508 and inside the liner 510 such that the heating fluid casing 512 extends through the generally vertical segment and through the generally horizontal segment. The heating fluid casing 512 is closed along the length of the casing 512 and is closed at the downhole end 514 to isolate the interior of the heating fluid casing 512 from a remainder of the interior of the liner 510 and the outer casing 508.

[0060] A heating fluid tube 516 is inserted into the heating fluid casing 512 such that the heating fluid tube 516 extends through the generally vertical segment and the generally horizontal segment of the well 500. The heating fluid tube 516 is open at an end 518 thereof for the flow of heating fluid through the heating fluid tube 516, out the end, and into the heating fluid casing 512. The heating fluid tube 516 may be insulated, for example, utilizing vacuum insulated tubing, or tubing insulated with any other suitable material, such as, inert gas, to retain heat while travelling through the heating fluid tube 516. The heating fluid is injected through the heating fluid tube 516 and is returned to the surface through the heating fluid casing 512.

[0061] The temperature in the generally horizontal segment of the well 500 may be monitored utilizing, for example, a DTS or ATS 520, as described above with reference to FIG. 3. The pressure in the well 500 may also be monitored utilizing a pressure sensor 522 or utilizing a DTS.

[0062] In the example illustrated in FIG. 5, the steam facilities 524 that are utilized to provide steam to the injection well during, for example, SAGD
production, are utilized prior to beginning production to provide pressurized fluid, which may be steam or water, that is injected into the heating fluid tube 516 and exits the heating fluid tube 516 downhole, into heating fluid casing 512. The heating fluid is returned to the surface and provided to a disposal facility 526, recirculated through the steam facilities 524, or a combination thereof. Optionally, the heating fluid may be produced water, which is water produced from, for example, another production well from which reservoir fluids, including water, are produced.

[0063] A sectional side view of yet another example of a well 600 is shown in FIG. 6. The well 600 may be, for example, a production well of a well pair or an injection well. Alternatively, the well 600 may be a well that is disposed intermediate well pairs or adjacent to a well pair, also referred to as an infill well or a well drilled using Wedge WeIITM technology. The well 600 includes many similarities to the well described with reference to FIG. 5.

[0064] As with the well 500 described above, the well 600 includes a heating fluid casing 612 that extends inside the outer casing 608 and inside the liner 610 such that the heating fluid casing 612 extends through the generally vertical segment and through the generally horizontal segment. The heating fluid casing 612 is closed along the length of the casing 612 and is closed at the downhole end 614 to isolate the interior of the heating fluid casing 612 from a remainder of the interior of the liner 610 and the outer casing 608.

[0065] A heating fluid tube 616 extends through the heating fluid casing 612. The heating fluid tube 616 is open at an end 618 thereof for the flow of heating fluid through the heating fluid tube 616, out the end, and into the heating fluid casing 612. The heating fluid tube 616 may be insulated, for example, utilizing vacuum insulated tubing, or tubing insulated with any other suitable material, such as, inert gas, to retain heat while travelling through the heating fluid tube 616. The heating fluid is injected through the heating fluid tube 616 and is returned to the surface through the heating fluid casing 612.

[0066] The temperature in the generally horizontal segment of the well 600 may be monitored utilizing, for example, a DTS or ATS 620 and the pressure in the well 600 may be monitored utilizing a pressure sensor 622 or utilizing a DTS.

[0067] As with the example described above with reference to FIG. 3, a fluid tank 624 and a pump 626 are utilized above ground for the circulation of fluid, such as water.
The fluid from the fluid tank 624 is pressurized utilizing the pump 626. In the example illustrated in FIG. 6, however, a line heater 628 extends along a portion of the heating fluid tube 616, in the horizontal segment of the well. The line heater 628 is utilized to heat the heating fluid. The line heater may be, for example, a resistive element line heater, an electromagnetic induction line heater, or any other suitable heater or heating apparatus. Thus, pressurized fluid is injected into the heating fluid tube 616, is heated along the heating fluid tube 616, and exits the heating fluid tube 616 into heating fluid casing 612. The heating fluid is returned to the surface, to the fluid tank 624, via the heating fluid casing 612.

[0068] A sectional side view of still another example of a well 700 is shown in FIG. 7. The well 700 may be, for example, a production well of a well pair or an injection well. Alternatively, the well 700 may be a well that is disposed intermediate well pairs or adjacent to a well pair, also referred to as an infill well or a well drilled using Wedge WeIITM technology. The well 700 includes many similarities to the well described with reference to FIG. 6 and to the well 500 described with reference to FIG.
5.

[0069] As with the well 600, the well 700 includes a heating fluid casing 712 that extends inside the outer casing 708 and inside the liner 710 such that the heating fluid casing 712 extends through the generally vertical segment and through the generally horizontal segment. The heating fluid casing 712 is closed along the length of the casing 712 and is closed at the downhole end 714 to isolate the interior of the heating fluid casing 712 from a remainder of the interior of the liner 710 and the outer casing 708.

[0070] A heating fluid tube 716 extends through the heating fluid casing 712. The heating fluid tube 716 is open at an end 718 thereof for the flow of heating fluid through the heating fluid tube 716, out the end, and into the heating fluid casing 712. The heating fluid tube 716 may be insulated, for example, utilizing vacuum insulated tubing, or tubing insulated with any other suitable material, such as, inert gas, to retain heat while travelling through the heating fluid tube 716. The heating fluid is injected through the heating fluid tube 716. A line heater 728 extends along a portion of the heating fluid tube 716, in the horizontal segment of the well. The line heater 728 is utilized to heat the heating fluid. The line heater may be, for example, a resistive element line heater, an electromagnetic induction line heater, or any other suitable heater or heating apparatus. In this example, a packer 730 is disposed in the annular space around the heating fluid tube 716, between the heating fluid casing 712 and the heating fluid tube 716, near the heel of the well 700. The packer 730 inhibits the flow of heating fluid from the heating fluid casing 712, back to the surface. A valve or valves 732 are disposed along the heating fluid tube 716, in the horizontal segment of the well 700.
The valves are one-way valves that facilitate the flow of heating fluid in one direction through the heating fluid tube 716, from the vertical segment of the well 700 into the horizontal segment of the well 700, and facilitate the flow of heating fluid from heating fluid casing 712 into the heating fluid tube 716 in the horizontal segment of the well 700.
A pump 734 pumps the heating fluid along the heating fluid tube 716 in the horizontal segment of the well 700. Thus, the packer 730, the valves 732, the pump 734, and the heater 728 are utilized to continuously circulate and heat the heating fluid downhole. As previously described, the heating fluid may be, for example, subsaturated water.

[0071] By heating and circulating the heating fluid downhole, rather than circulating the fluid back to the surface, less heat is lost in the vertical segment of the well 700, improving heating efficiency.

[0072] The temperature in the generally horizontal segment of the well 700 may be monitored utilizing, for example, a DTS or ATS 720 and the pressure in the well 700 may be monitored utilizing a pressure sensor 722 or utilizing a DTS.

[0073] A fluid tank 724 and a pump 726 are utilized above ground to pump the fluid, for example, water downhole. In this example, however, the pump 734 is utilized for continuous circulation of heating fluid in the horizontal segment of the well.

[0074] The process of FIG. 4 may be carried out in any of the example wells, as illustrated in FIG. 3, FIG. 5, FIG. 6, and FIG. 7.

[0075] Advantageously, relatively high pressure heating fluid is circulated through the well to heat the reservoir around the well by conduction. The heating fluid is isolated from the reservoir, facilitating the use of relatively high pressure and temperature. For example, subsaturated water may be utilized at high temperature.
Because higher pressures are utilized, heating fluid at higher temperatures may also be utilized. Further, higher pressures may be utilized for reservoirs in the presence of a mobile fluid zone, or thief zone, without the heating fluid contacting or being in communication with the thief zone. With the use of higher pressures, higher temperatures may also be utilized.

[0076] The following examples are submitted to further illustrate embodiments of the present invention. These examples are intended to be illustrative only and are not intended to limit the scope of the present invention.

[0077] The examples herein illustrate that the start-up process of circulating high pressure heating fluid through wells prior to producing hydrocarbons is utilized to achieve improved uniformity of steam distribution, also referred to as conformance, during production of hydrocarbons and results in improved rate of hydrocarbon recovery.

[0078] Examples 1, 2 and 3 herein were developed utilizing simulation software to model heavy hydrocarbon recovery. The simulated reservoir, at a depth of 250 m, had a thickness of 25 m, a length of 1,400 m, and a width of 42 m. The top 3 m of the simulated reservoir was established as a water zone, also referred to as a thief zone, followed by a 5 m transition zone, a zone in which the oil saturation is <100%
and the water saturation is >0%, and a 17 m oil rich zone, also referred to as a pay zone. A
zone of low oil saturation was included in the reservoir, at a depth of 9 m from the top of the reservoir to 18 m from the top of the reservoir. The zone of low oil saturation extended from 250 m to 450 m along the length of 1,400 m and the full width of the simulated reservoir.

[0079] The reservoir conditions were set as follows:
temperature prior to circulation of heating fluid: 13 C
(13. Lean Zone (Porosity) = 0.36 horizontal permeability = 3.0 Darcy vertical permeability = 2.25 Darcy reference pressure of 1225 kPa at the top of the oil rich zone;
water saturation in the lean (water) zone = 0.80 water saturation in the transition zone = 0.55 water saturation in the oil rich zone = 0.25 oil saturation in the lean (water) zone = 0.20 oil saturation in the transition zone = 0.45 oil saturation in the oil rich zone = 0.75

[0080] The reservoir rock properties are as follows:
porosity reference pressure = 2,066.32 kPa compressibility = 3.5e-6 1/kPa volumetric heat capacity = 2.35e6 J(m3 C) rock thermal conductivity = 209e3 J(m=day. C) water thermal conductivity = 5.35e4 J/(m=day. C) oil thermal conductivity = 1.15e4 J/(m=day. C) gas thermal conductivity = 14.4 J/(m=day. C)

[0081] A graphical representation of oil saturation of the reservoir is illustrated in FIG. 8. The reservoir is represented by grid blocks in FIG. 8, which represents two dimensions of the reservoir, including the depth along the y axis and the length along the X axis. The grid blocks each represent 1 min depth and 50 m in length along the reservoir. The zone of low oil saturation is represented in the reservoir by lighter shading than a remainder of the reservoir at the same depth. The zone is shown at a depth of 9 m, which is represented by 9 grid blocks, from the top of the reservoir, to 18 m, represented by 18 grid blocks from the top of the reservoir. The zone of low oil saturation extends from 250 m, represented by 5 grid blocks from the left of the reservoir, to 450 m, represented by 9 grid blocks from the left of the reservoir.

[0082] Three example simulations and a pilot test example are referred to herein.

[0083] EXAMPLE 1

[0084] High pressure oil was circulated in both the production well and the injection well of a SAGD well pair in accordance with the present disclosure for 4 months prior to hydrocarbon recovery. The oil circulation was isolated from the reservoir, referred to as hot oil closed circulation (Hot Oil CC).

[0085] EXAMPLE 2

[0086] High pressure steam was circulated in both the production well and the injection well of a SAGD well pair in accordance with the present disclosure for 4 months prior to hydrocarbon recovery. The steam circulation was isolated from the reservoir, referred to as steam closed circulation (Steam CC).

[0087] EXAMPLE 3

[0088] High pressure steam was circulated in both the production well and the injection well of a SAGD well pair for 4 months prior to hydrocarbon recovery.
The steam in this example was not closed off and therefore not isolated from the reservoir.
The steam was circulated through a tubing string to the toe of the wells and into the reservoir, referred to as Steam Circulation.

[0089] EXAMPLE 4

[0090] Steam CC was also piloted in the field, utilizing a SAGD well pair positioned in the Grand Rapids geological formation at an oil sands facility in Alberta, Canada. The pilot consisted of a Steam CC technology demonstration in a manner similar to that shown in FIG. 5. For the Steam CC pilot, the injection well and the production well were completed with the same configuration. The configuration included a generally vertical segment and a generally horizontal segment that were joined at a heel of the well. The well included an outer casing that extended from the surface through the generally vertical segment of the well, through the heel and to the generally horizontal segment. A 7" outer diameter liner was coupled to the outer casing and extended along the generally horizontal segment of the well.

[0091] A 5" outer diameter heating fluid casing in the well extended inside the outer casing and inside the liner such that the heating fluid casing extended through the generally vertical segment and through the generally horizontal segment. The heating fluid casing was closed along the length of the casing and was closed at the downhole end to isolate the interior of the heating fluid casing from a remainder of the interior of the liner and the outer casing.

[0092] A 3.5" outer diameter heating fluid tube was inserted into the heating fluid casing such that the heating fluid tube extended through the generally vertical segment and the generally horizontal segment of the well. The heating fluid tube was open at an end thereof for the flow of heating fluid through the heating fluid tube, out the end, and into the heating fluid casing. The heating fluid (steam in this example, provided by steam facilities) was injected at a pressure of about 7,400 kPag and a temperature of about 290 C through the heating fluid tube and returned to the surface through the heating fluid casing at a pressure of about 1,000 kPag to about 2,000 kPag.
The returned steam was transported to a disposal well.

[0093] The temperature and pressure in the generally horizontal segment of the well were monitored utilizing a fiber optic sensor and a bubble tube liquid level measurement system. The outer annular pressure was observed to range between about 1,600 kPag and 2,600 kPag during the Steam CC pilot. During the Steam CC

pilot, reservoir fluid that entered the horizontal segment of the well through the liner was produced to the surface through the annulus between the outer casing and the heated fluid casing. The pressure of the reservoir fluid was about 500 kPa to about 1,500 kPa and the production of the reservoir fluid provided evidence that the process was generating heat in the reservoir. Producing the reservoir fluid also prevented over-pressuring in the reservoir during the Steam CC process.

[0094] Steam CC was commenced in the injection well of the pilot about 1 month after Steam CC was commenced in the production well of the pilot. The pilot was monitored for more than 5 months from the time Steam CC was commenced in the production well. During the pilot, the production well and injection well were shut-in (steam circulation through the heating fluid tube and into the heating fluid casing was stopped) from time to time, for a few days each time, to monitor the decrease in temperature or perform maintenance as needed at the wellhead.

[0095] RESULTS

[0096] FIG. 9 shows the cumulative oil (m3) recovered over the period of days for each of simulation Examples 1 (referred to as Hot Oil CC), 2 (referred to as Steam CC), and 3 (referred to as Steam Circulation). As illustrated, both Hot Oil CC
(Example 1) and Steam CC (Example 2) led to higher oil recovery compared to Steam Circulation (Example 3). Hot Oil CC (Example 1) showed the greatest oil recovery of the three simulations. FIG. 18 shows the daily oil production rate (m3/d) over the same simulated period of 2920 days for each of Examples 1, 2, and 3. Without being limited to theory, the higher cumulative oil (FIG. 9) and higher initial oil production rate (FIG. 18) predicted in the first 1-2 years after carrying out the method for increasing hydrocarbon mobility, may be due to higher temperatures and better conformance in the hydrocarbon reservoir when Hot Oil CC (Example 1) or Steam CC (Example 2) are utilized compared to Steam Circulation (Example 3), the latter of which does not isolate the circulation from the reservoir.

[0097] FIG. 10 shows the cumulative steam to oil ratio (CSOR) over the period of 2920 days for each of Examples 1, 2, and 3. The cumulative steam to oil ratio is lowest for Hot Oil CC (Example 1).

[0098] FIG. 11, FIG. 12, and FIG. 13 illustrate steam conformance, or steam distribution, within the reservoir after 4 months of carrying out the method for increasing hydrocarbon mobility and 18 months of hydrocarbon production for the SAGD well pairs of simulation Examples 1, 2, and 3, respectively.

[0099] A comparison of FIG. 11, FIG. 12, and FIG. 13 shows that both Hot Oil CC
(Example 1) and Steam CC (Example 2) markedly improved conformance of steam in the reservoir even 18 months after circulation was stopped and production was started, by comparison to Steam Circulation. As shown in FIG. 13, the steam is concentrated at the toe of the injection well and at the zone of low oil saturation where steam is lost to the water zone. Conformance is best for the reservoir after Hot Oil CC, as illustrated in FIG. 11.

[00100] FIG. 14 shows the changes in bottom-hole temperature collected over a period of 200 days from fiber optic temperature sensors located at three locations (toe, mid-section, and heel) along the horizontal segment of the production well and the injection well of the pilot, each of which were configured as described in this Example 4.

[00101] FIG. 15 shows the results from modeling the temperature of the Steam CC
pilot process in comparison to actual temperatures from an observation well positioned near the heel of the pilot SAGD well pair. The observation well, positioned about 1.5 m laterally from the injector and about 2.5 m from the producer, was equipped with piezometers to measure temperature and pressure. FIG. 15 shows the change in temperature at the observation well over a period of 200 days, as well as predicted temperatures at the same locations determined from mechanistic reservoir models. The sensors T2, T3 and 14 were located at depths that correspond to the production well depth, inter-well depth and injection well depth, respectively.

[00102] FIG. 16 shows the predicted and actual inter-well temperature profile along the length of the well pair over a period of about 4 months of Steam CC
operation.
The inter-well region corresponds to mid-distance between the injection well and the production well in the well pair, where the temperature of reservoir fluids is expected to take the longest time to increase during Steam CC. The inter-well temperature was predicted using empirical methods and mechanistic reservoir models and, without being limited to theory, is one criterion for identifying when to transition the well pair from the Steam CC or Hot Oil CC phase to the hydrocarbon production phase. FIG. 17 is a visual representation of the predicted temperature distribution in the reservoir from the mechanistic reservoir model. In FIG. 17, the darkest areas represent cooler temperatures. .

[00103] The described embodiments are to be considered in all respects only as illustrative and not restrictive. The scope of the claims should not be limited by the preferred embodiments set forth in the examples, but should be given the broadest interpretation consistent with the description as a whole. All changes that come with meaning and range of equivalency of the claims are to be embraced within their scope.

Claims (22)

Claims

1. A process for increasing overall mobility of reservoir fluid utilizing a well including a generally vertical segment extending from a surface, and a generally horizontal segment extending into a hydrocarbon-bearing formation, the process comprising:
inserting a casing having a closed end into the well such that the casing extends through the generally vertical segment, from a surface, and into the generally horizontal segment of the well;
inserting a tube into the casing, the tube extending through the generally vertical segment and into the generally horizontal segment of the well;
injecting a heating fluid through the tube, the heating fluid exiting the tube in the generally horizontal segment of the well and entering the casing, the casing being closed to isolate the heating fluid from the hydrocarbon-bearing formation, such that the heating fluid returns to the surface.

2. The process according to claim 1, wherein the heating fluid is heated to conduct heat through the casing and into the hydrocarbon-bearing formation.

3. The process according to claim 2, wherein the heating fluid comprises steam heated to a temperature of about 200 C to about 400 C.

4. The process according to claim 2, wherein the heating fluid comprises oil heated to a temperature of about 200 C to about 600 C.

5. The process according to claim 1, wherein the heating fluid is heated prior to injecting the heating fluid through the tube.

Date Recue/Date Received 2022-03-04

6. The process according to claim 1, wherein the heating fluid is heated below the surface.

7. The process according to claim 1, wherein the heating fluid is heated in the tube, in a heel section, or in the generally horizontal segment of the well.

8. The process according to claim 1, wherein the heating fluid is heated and injected into the tube under pressure sufficient to reach a downhole pressure of about 2 MPa to about 30 MPa.

9. The process according to claim 1, wherein the heating fluid comprises water.

10. The process according to claim 1, wherein the heating fluid comprises subsaturated water.

11. A system for increasing overall mobility of reservoir fluid utilizing a well including a generally vertical segment and a generally horizontal segment extending into a hydrocarbon-bearing formation, the system comprising:
a casing extending through the generally vertical segment and into the generally horizontal segment of the well, the casing including a closed end in the generally horizontal segment of the well;
a tube extending through the casing, through the generally vertical segment and into and through the generally horizontal segment of the well, the tube including an opening to facilitate the flow of heating fluid from the tube and into the casing through which the heating fluid is returned to the surface, wherein the casing is closed to isolate the heating fluid from the hydrocarbon-bearing formation.

Date Recue/Date Received 2022-03-04

12. The system according to claim 11, comprising a heater to heat the heating fluid for conducting heat through the casing and into the hydrocarbon-bearing formation.

13. The system according to claim 12, wherein the heater is located above surface to heat the heating fluid prior to injecting the heating fluid through the tube.

14. The system according to claim 11, comprising a heater and a pump to heat and pressurize the heating fluid.

15. The system according to claim 11, wherein the heating fluid comprises water.

16. The system according to claim 11, wherein the heating fluid comprises subsaturated water.

17. The system according to claim 11, wherein the heating fluid comprises oil.

18. A process for increasing overall mobility of reservoir fluid utilizing a well including a generally vertical segment extending from a surface, and a generally horizontal segment extending into a hydrocarbon-bearing formation, the process comprising:
injecting a heating fluid through a tube that extends through the generally vertical segment and into the generally horizontal segment of the well, the heating fluid exiting the tube in the generally horizontal segment of the well and entering a casing, near a closed end thereof, through which the heating fluid is returned to the surface, the casing being closed to isolate the heating fluid from the hydrocarbon-bearing formation;
heating the heating fluid to transfer heat to the casing and to thereby conduct heat to the hydrocarbon-bearing formation.

Date Recue/Date Received 2022-03-04

19. The process according to claim 18, wherein heating the heating fluid comprises heating the heating fluid prior to injecting the heating fluid into the tube.

20. The process according to claim 18, wherein heating the heating fluid comprises heating the heating fluid below the surface.

21. The process according to claim 18, wherein heating the heating fluid comprises heating the heating fluid in the tube, in a heel section or in the generally horizontal segment of the well.

22. The process according to claim 18, wherein the heating fluid is heated and injected into the tube at a pressure sufficient to reach a downhole pressure of about 2 MPa to about 30 MPa.

Date Recue/Date Received 2022-03-04