CA2890491C - Hydrocarbon recovery start-up process - Google Patents

Abstract

A process startup of hydrocarbon recovery utilizing a well including a generally vertical section and a generally horizontal section extending into a hydrocarbon- bearing formation. The process includes injecting a fluid through a tube that extends through the generally vertical section and the generally horizontal section of the well, the fluid exiting the tube in the generally horizontal section of the well, lifting the fluid utilizing artificial lift, after transferring heat to the hydrocarbon-bearing formation, to a head of the well to thereby circulate the fluid prior to production, discontinuing circulating the fluid and beginning production of hydrocarbons from the hydrocarbon-bearing formation.

Description

HYDROCARBON RECOVERY START-UP PROCESS
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 startup of hydrocarbon recovery are desirable.
Summary

[0008] According to an aspect of an embodiment, a process is provided for startup of hydrocarbon recovery utilizing a well including a generally vertical section and a generally horizontal section extending into a hydrocarbon-bearing formation.
The process includes injecting a fluid through a tube that extends through the generally vertical section and the generally horizontal section of the well, the fluid exiting the tube in the generally horizontal section of the well, lifting the fluid utilizing artificial lift, after transferring heat to the hydrocarbon-bearing formation, to a head of the well to thereby circulate the fluid prior to production, discontinuing circulating the fluid, and beginning production of hydrocarbons from the hydrocarbon-bearing formation.

[0009] Artificially lifting the condensed steam to the wellhead facilitates circulation at lower pressures than the pressure that is otherwise utilized to ensure that the condensed steam is returned to the surface.
Brief Description of the Drawings

[0010] Embodiments of the present invention will be described, by way of example, with reference to the drawings and to the following description, in which:

[0011] FIG. 1 is a sectional view through a reservoir, illustrating a SAGD well pair;

[0012] FIG. 2 is a sectional side view illustrating an injection and a production well pair;

[0013] FIG. 3A is a sectional side view illustrating a production well according to an embodiment;

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

[0015] FIG. 4 is a flowchart illustrating a process of start-up of hydrocarbon recovery from a hydrocarbon-bearing formation;

[0016] FIG. 5 is a sectional view through a reservoir and through a generally horizontal segment of a SAGD well pair according to another embodiment;

[0017] FIG. 6 is a sectional view through a reservoir and through a generally horizontal segment of a SAGD well pair according to another embodiment.
Detailed Description

[0018] 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.

[0019] The disclosure generally relates to a process for startup of hydrocarbon recovery utilizing a well including a generally vertical section and a generally horizontal section extending into a hydrocarbon-bearing formation. The process includes injecting a fluid through a tube that extends through the generally vertical section and the generally horizontal section of the well, the fluid exiting the tube in the generally horizontal section of the well, lifting the fluid utilizing artificial lift, after transferring heat to the hydrocarbon-bearing formation, to a head of the well to thereby circulate the fluid prior to production, discontinuing circulating the fluid, and beginning production of hydrocarbons from the hydrocarbon-bearing formation.

[0020] 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.

[0021] 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 horizontal segment 102 that extends near the base or bottom 104 of the hydrocarbon reservoir 106. The injection well 108 also includes a generally horizontal segment 110 that is disposed generally parallel to and is spaced vertically above the horizontal segment 102 of the hydrocarbon production well 100.

[0022] As referred to above, at startup of a SAGD well pair or at startup of 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.

[0023] Canadian Patent 2,162,741, issued December 20, 2005 to Nzekwu et al.
discloses a hydrocarbon production method in which a downhole production pump is utilized to pump heated oil and steam condensate during the production of hydrocarbons. Steam injection and hydrocarbon production are simultaneous and continuous throughout the life of the well, however, and Improvements in startup of hydrocarbon recovery are desirable.

[0024] A sectional side view of an example of a production well 300 is shown in FIG. 3A. As shown in FIG. 3A, the production well 300 includes the generally horizontal segment 302. A tubing 304, which may be, for example, a non-insulated tubing, an insulated tubing or insulated coil tubing, such as a vacuum insulated tubing, is utilized to deliver heated fluid, including steam, to the hydrocarbon production well. The tubing 304 extends from the wellhead 306, through a heel portion 308 of the production well 300, and along the generally horizontal segment 302. Use of insulated tubing reduces the amount of heat loss during travel of the fluid from the wellhead 306 to the generally horizontal segment 302. During steam circulation, the steam transfers heat to the formation, condenses, and is returned to the surface as water. The use of the insulated tubing reduces the wasted energy caused by heat transfer to the condensed water and heat transfer between steam entering the well and condensed water returning from the well as the water collects in the well and is returned to the wellhead.

[0025] The tubing 304 generally follows the contour of the production well 300 and may include perforations or flow control devices or both perforations and flow control devices along a generally horizontal portion 312 of the tubing 304 to facilitate distribution of the steam along the generally horizontal segment 302 of the production well 300.

[0026] The tubing is described herein as insulated tubing 304.
Alternatively, the tubing may be a non-insulated tubing. The use of non-insulated tubing reduces capital expenditure and has a smaller thickness of pipe wall. Thus, non-insulated tubing with the same outside diameter as insulated tubing, has a larger inside diameter, and therefore larger cross sectional area available for flow, facilitating circulation of larger volumes of steam and reducing frictional pressure losses as a result of fluid flow along the pipe.

[0027] An electric submersible pump (ESP) 314 is utilized to pump fluids, including the condensed water as well any hydrocarbons that may be produced during startup of the well, to the wellhead. The ESP 314 may be a slim-hole ESP that is coupled to a tubing string 316, such as tubing or a coil tubing string of 2 3/8" (6.03 cm) internal diameter. The ESP 314 is disposed at or near the heel of the production well 300 and the tubing string 316 is coupled to the ESP 314 and extends to the wellhead 306 for the passage of fluids pumped from the ESP 314. Rather than an ESP, any other suitable artificial lift may be utilized.

[0028] Optionally, a distributed temperature sensing system (DTS) or array temperature sensing system (ATS) 318, such as a downhole fiber optic temperature sensor, is disposed in the well and extends along the length of the generally horizontal segment 302. The DTS or ATS is utilized to sense the temperature along the length of the generally horizontal segment 302 to obtain a real-time temperature profile across the generally horizontal segment 302 of the production well 300. The DTS may also be utilized in the generally vertical segment of the production well 300. The DTS
may also be utilized to detect pressure.

[0029] As indicated above, any suitable artificial lift may be utilized.
According to one embodiment, gas lift or jet pumps may be utilized. Gas lift may be advantageous because an ESP may be susceptible to gas locking. A sectional side view of another example of a production well 320 is shown in FIG. 313. As shown in FIG. 3B, the production well 320 includes the generally horizontal segment 302. As described with reference to FIG. 3A, a tubing 304 or insulated coil tubing, such as a vacuum insulated tubing, is utilized to deliver heated fluid, including steam, to the hydrocarbon production well. The tubing 304 extends from the wellhead 306, through a heel portion 308 of the production well 320, and along the generally horizontal segment 302. Use of insulated tubing reduces the amount of heat loss during travel of the fluid from the wellhead 306 to the generally horizontal segment 302. During steam circulation, the steam transfers heat to the formation, condenses, and is returned to the surface as water. The use of the insulated tubing reduces the wasted energy caused by heat transfer to the condensed water and heat transfer between steam entering the well and condensed water returning from the well as the water collects in the well and is returned to the wellhead.

[0030] The tubing 304 generally follows the contour of the production well 320 and may include perforations or flow control devices or both perforations and flow control devices along a generally horizontal portion 312 of the tubing 304 to facilitate distribution of the steam along the generally horizontal segment 302 of the production well 320.

[0031] Gas lift is utilized to pump fluids, including the condensed water as well any hydrocarbons that may be produced during startup of the well, to the wellhead. A
tubing string 322, which may be tubing or a coil tubing string of 2 3/8" (6.03 cm) internal diameter, is utilized for gas lift. The tubing 322 includes ports 324 at a lower end thereof, at or near the heel of the production well 320 and gas is injected into the annular space between the tubing strings 304 and 322 to artificially lift the fluids as the fluids pass through the ports 324 and are lifted from the production well 320.

[0032] Optionally, a distributed temperature sensing system (DTS) or array temperature sensing system (ATS) 318 may also be included.

[0033] A flowchart illustrating a process for startup of hydrocarbon recovery from a hydrocarbon-bearing formation is shown in FIG. 4. The process is carried out to startup hydrocarbon recovery 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. 3A and FIG. 3B. The process may contain additional or fewer processes than shown or described, and may be performed in a different order.

[0034] Heating fluid, such as heated water or steam, is injected into the well at 402, through the tubing 304. The heating fluid is injected at a pressure sufficient to reach a downhole pressure that is within about 500 kPa of the pressure in the reservoir.
For example, for a reservoir pressure of about 1200 kPa, the heating fluid is injected at a pressure to reach a downhole pressure of from about 700 kPa to about 1700 kPa.
Such a pressure of plus or minus 500 kPa of the reservoir pressure is suitable for circulation of the heating fluid within the wellbore.

[0035] Thus, the heating fluid is injected at low pressure compared to prior startup processes. The use of insulated tubing as the tubing 304 reduces the amount of heat loss during travel of the fluid from the wellhead 306 to the generally horizontal segment 302 compared to a non-insulated tubing string.

[0036] A surface heater or steam-production facilities may be utilized to produce the heating fluid that is injected down the well. Alternatively, a subsurface heater can be located in an upper part of the tubing 304, or the insulated coil tubing, in the generally vertical segment of the well. Water can be injected into the well, through the tubing 304, which may be insulated tubing, such that the water flashes to steam as the water travels past the heater, toward the generally horizontal segment 302.

[0037] As described above, the generally horizontal portion 312 of the tubing 304 may include perforations such that heating fluid is delivered to several locations along the length of the generally horizontal segment 302. Alternatively, or in addition, heating fluid travels along the length of the tubing 304 and is delivered to the toe of the production well 300.

[0038] As the heating fluid is injected into the well, the region of the reservoir around the generally horizontal segment 302 rises because the heating fluid is at a temperature that is above the ambient temperature in the reservoir. When steam is injected, the steam condenses and the condensed water accumulates in the generally horizontal segment 302. In addition to the water, some mobilized hydrocarbons may be collected in the generally horizontal segment 302. Because the fluid is injected at a relatively low pressure, for example, compared to prior art SAGD processes, the accumulated fluid does not naturally flow toward the wellhead. Thus, artificial lift, such as the ESP 314, is utilized to lift the accumulated fluids to the wellhead 306 at 404. A
slim-hole ESP 314 may be utilized such that the tubing 304, and the ESP 314 and tubing string 316 fit in a single well. Thus, water, which may be in the form of steam, is circulated through the well to heat the reservoir.

[0039] The injection of heating fluid 402 may be continuous during artificial lift of accumulated fluid to the wellhead at 404. Alternatively, the injection of heating fluid 402 may be discontinuous such that injection is periodically stopped while artificially lifting the accumulated fluid to the wellhead at 404 continues. Injection of heating fluid 402 may begin again while artificially lifting accumulated fluid to the wellhead.
In another alternative, the injection of heating fluid 402 may be continuous and artificial lift of accumulated fluid 404 may be discontinuous.

[0040] The reservoir is monitored at 406 by monitoring well conditions, such as temperature. For example, the reservoir may be monitored utilizing the DTS 318 that extends through the hydrocarbon production well to obtain a real-time temperature profile across the generally horizontal segment of the hydrocarbon production well.
When the temperature is not raised sufficiently to meet a threshold at 408, the circulation of fluid at 402 and 404 continues. When the well conditions meet a threshold at 408, the method continues at 410. For example, based on a lowest-measured temperature along the length of the generally horizontal segment 302, as measured by the DTS, a temperature at a location of about 2.5 to 3 meters away in the reservoir may be calculated based on known temperature calculations. When the temperature at this location of about 2.5 to 3 meters away in the reservoir is raised such that the temperature meets a threshold temperature, the method continues at 410.

Alternatively, a highest measured temperature, an average measured temperature, or a measured temperature 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 method continues at 410. The circulation of heating fluid by injection of heating fluid at 402 and artificial lift of fluids at 404 may continue, for example, for about 3 months to about 6 months.

[0041]
Heating fluid injection is discontinued at 410. Artificial lift, such as the use of the ESP 314, may continue to lift accumulated fluids from the production well to continue to lift fluids that accumulate after heating fluid injection stops.
The tubing 304 may be removed from the well and, after lifting the fluids from the well, the ESP 314 and the tubing string 316 may be removed from the well. The tubing 304, the ESP
314 and the tubing string 316 may be utilized for startup of another well. Optionally, the insulated tubing may stay in the well, for example, for several months after startup without adversely affecting production. For example, for a production well in a SAGD
pair, the tubing 304, the ESP 314, and the tubing string 316 may all remain in the production well for up to one year after installation such that the production well is utilized during SAGD prior to removal of the tubing 304, the ESP 314, and the tubing string 316. Thus, the tubing 304 may be removed prior to starting hydrocarbon production or during hydrocarbon production. Heating fluid is not circulated during hydrocarbon production.

[0042]
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 302. In addition to steam injection into the steam injection well, light hydrocarbons, such as the 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, 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 302. The fluids may also include gases such as steam and production gases from the SAGD process. Optionally, a second, larger ESP may be utilized to lift the hydrocarbons to the surface of the production well.

[0043] Thus, heating fluid is circulated through a well at relatively low pressure utilizing insulated tubing . The heating fluid is circulated prior to production of hydrocarbons from the well. Circulation is discontinued and production begins from the same well through which heating fluid was circulated.

[0044] A sectional view through a reservoir and through a generally horizontal segment of a SAGD well pair is illustrated in FIG. 5. In the present example, a mobile fluid zone 502 is disposed above the reservoir 504. The process for startup of hydrocarbon recovery, as shown in FIG. 4 and described above, is performed by injecting fluid at 402 through an insulated tubing in the production well. The accumulated fluid is lifted to the wellhead at 404 and the well conditions are monitored at 406. In response to a temperature, such as the lowest measured temperature along the generally horizontal segment 506 of the production well meeting a threshold temperature at 408, heating fluid injection is discontinued at 410 and hydrocarbon production begins 412.

[0045] The generally horizontal segment 506 of the production well is below the generally horizontal segment 508 of the injection well and is further from the top mobile fluid zone 502. Thus, the steam chamber 510 that forms begins at the production well, which is father from the mobile fluid zone 502, advantageously delaying the communication of the steam chamber 510 with the mobile fluid zone 502, thereby reducing the loss of heat and steam to the mobile fluid zone.

[0046] The process illustrated in FIG. 4 is described above with reference to FIG.
3A, FIG. 3B, and to FIG. 5 in which the process is carried out in a production well of a SAGD well pair. The process is not limited to a production well, however. For example, the process shown in FIG. 4 may be carried out in an injection well of a SAGD
well pair, or may be carried out in a single 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.

[0047] To reduce the chance of early fluid communication between the steam chamber and a mobile fluid zone, the production well is circulated to achieve heating along the production well and into the injection well as described. A
relatively short steam cycle of about 1 month, for example, in the injection well may be utilized after about 3 months to about 6 months of circulation in the production well to heat across the injection well.

[0048] A sectional view through a reservoir and through a generally horizontal segment of a SAGD well pair is illustrated in FIG. 6. In this example, a mobile fluid zone 602 is disposed below the reservoir 604. The process for startup of hydrocarbon recovery, as shown in FIG. 4 and described above, is performed by injecting fluid at 402 through an insulated tubing in the injection well. The accumulated fluid is artificially lifted through the tubing string in the injection well to the wellhead at 404 and the well conditions are monitored at 406. In response to a temperature, such as the lowest measured temperature along the generally horizontal segment 606 of the injection well or production well, meeting a threshold temperature at 408, heating fluid injection is discontinued at 410 and hydrocarbon production begins 412 by injecting steam through the injection well and producing fluids through the production well.

[0049] The generally horizontal segment 606 of the injection well is above the generally horizontal segment 608 of the production well and is further from the bottom mobile fluid zone 602. Thus, the steam chamber 610 that forms begins at the injection well, which is farther from the mobile fluid zone 602, advantageously delaying the communication of the steam chamber 610 with the mobile fluid zone 602, thereby reducing the loss of heat and steam to the mobile fluid zone.

[0050] According to another example, the process is carried out in a single well that is disposed intermediate well pairs. Such a well may be drilled, for example, about years after production is started in the neighboring well pairs. By carrying out the process of FIG. 4 in a single well, communication between a steam chamber that forms around the single well and the region of the reservoir that is heated from the injection of steam at neighboring well pairs is effectuated.

[0051] Advantageously, relatively low pressure fluid is circulated to heat the reservoir around the well. The low pressure reduces localized heating, increasing the effectiveness of the steam in heating the reservoir and improving conformance by comparison to the circulation of high pressure fluid. The reduced localized heating also reduces the chance of fracturing rock around the reservoir, which causes a loss of steam or hotspot development. Insulated tubing that may be utilized for the injection of the heating fluid also improves efficiency because less heat is lost during transport of the heating fluid and less heat is exchanged with the fluids that accumulate in the well and are returned to the surface. The process is carried out prior to recovery of hydrocarbons utilizing the well and facilitates production by improving conformance.

[0052] 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 (15)

Claims

1. A process for startup of hydrocarbon recovery utilizing a well pair including a first well having a generally vertical section and a generally horizontal section extending into a hydrocarbon-bearing formation, and a second well extending generally parallel to the first well, the process comprising:
injecting a fluid through a tube that extends through the generally vertical section and the generally horizontal section of the first well, the fluid exiting the tube in the generally horizontal section of the well, wherein the fluid is injected at a pressure that is within about 500kPa of a pressure in the hydrocarbon-bearing formation;
lifting the fluid utilizing artificial lift, after transferring heat to the hydrocarbon-bearing formation, to a head of the first well to thereby circulate the fluid prior to production;
discontinuing circulating the fluid utilizing the first well, and injecting steam into the hydrocarbon-bearing formation via one of the first well and a second well of the well pair while producing fluids including hydrocarbons from the hydrocarbon-bearing formation via the other of the first well and the second well of the well pair.

2. The process according to claim 1, wherein the tube comprises a non-insulated tube.

3. The process according to claim 1, wherein the tube comprises an insulated tube.

4. The process according to claim 1, comprising, while injecting, heating, in the generally vertical section of the first well, the fluid within the tube to provide steam.

5. The process according to claim 1, wherein injecting a fluid comprises injecting water and heating the water to form the steam.

Date Recue/Date Received 2021-08-24

6. The process according to claim 5, wherein heating comprises heating the water to form steam such that the fluid exits the tube as steam.

7. The process according to claim 1, wherein injecting a fluid comprises injecting steam.

8. The process according to claim 7, wherein the steam condenses during heat exchange and lifting comprises artificially lifiting the condensed water.

9. The process according to claim 1, wherein lifting comprises lifting utilizing a slim-hole electric submersible pump.

10. The process according to claim 1, wherein lifting comprises utilizing gas lift to artificially lift the fluid.

11. The process according to claim 1, wherein lifting comprises pumping utilizing an electric submersible pump.

12. The process according to claim 11, wherein producing fluids including hydrocarbons from the hydrocarbon-bearing formation via the other of the first well and the second well comprises utilizing a second electric submersible pump to pump the hydrocarbons to a wellhead.

13. The process according to claim 1, comprising monitoring well conditions prior to beginning production, wherein beginning production is carried out based on the well conditions.

14. The process according to claim 13, wherein monitoring comprises monitoring temperature along the generally horizontal section.

Date Recue/Date Received 2021-08-24

15. The process according to claim 1, wherein the first well is selected by selecting one of an injection well and a production well of a well pair, which is farther from a mobile fluid zone.

Date Recue/Date Received 2021-08-24