CA3014378A1 - Process for producing hydrocarbons from a subterranean hydrocarbon-bearing formation - Google Patents

Abstract

A process for recovering hydrocarbons from a subterranean hydrocarbon-bearing formation includes injecting an injection fluid into the hydrocarbon-bearing formation through an injection well including a substantially horizontal injection section in the hydrocarbon-bearing formation, and producing hydrocarbons from the hydrocarbon-bearing formation to a surface through a first production well including a substantially horizontal production section in the hydrocarbon-bearing formation. The injection section of the injection well is laterally offset from the production section of the first production well, and the injection well includes a side well extending substantially horizontally from the injection section toward a location along the production section or the production well includes the side well extending substantially horizontally from the location along production section toward the injection section. The process also includes selectively heating a region of the hydrocarbon-bearing formation that is near the location along the production section and vertically spaced from the first production well.

Description

PROCESS FOR PRODUCING HYDROCARBONS FROM A SUBTERRANEAN
HYDROCARBON-BEARING FORMATION
Technical Field [0001] The present disclosure relates to the production of hydrocarbons from a subterranean formation bearing heavy oil or bitumen.
Background

[0002] Extensive deposits of viscous hydrocarbons exist around the world.

Reservoirs of such deposits may be referred to as reservoirs of heavy hydrocarbon, heavy oil, extra-heavy oil, bitumen, or oil sands, and include large subterranean deposits in Alberta, Canada that are not susceptible to standard oil well production technologies. The hydrocarbons in such deposits are typically highly viscous and do not flow at commercially relevant rates at the temperatures and pressures present in the reservoir. For such reservoirs, various recovery techniques may be utilized to mobilize the hydrocarbons and produce the mobilized hydrocarbons from wells drilled in the reservoirs. For example, thermal techniques may be used to heat the reservoir to mobilize the hydrocarbons and produce the heated, mobilized hydrocarbons from wells.

[0003] Hydrocarbon substances of high viscosity are generally categorized as "heavy oil" or as "bitumen". Although these terms are in common use, references to heavy oil and bitumen represent categories of convenience, and there is a continuum of properties between heavy oil and bitumen. Accordingly, references to such types of oil herein include the continuum of such substances, and do not imply the existence of some fixed and universally recognized boundary between the substances.

[0004] One thermal method of recovering viscous hydrocarbons from a subterranean hydrocarbon-bearing formation using spaced horizontal wells is known as steam-assisted gravity drainage (SAGD). 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, steam is injected 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 from and near the injection well. The injection and production wells are located close to the base of the hydrocarbon deposit to collect the hydrocarbons that flow toward the production well.

[0005] Such thermal processes are extremely energy intensive, utilize significant volumes of water for the production of steam, and may require additional equipment to handle the steam or gasses produced.

[0006] A solvent may be used to aid a steam-assisted recovery process, in a so-called solvent-aided process (SAP). To further reduce steam use, solvent may be injected without steam in a solvent-only (solvent-based) recovery process.
Hydrocarbon solvent is generally used to improve mobility in the hydrocarbon reservoir, potentially improving production and/or reducing steam and/or heating requirements. However, the use of solvent can add significant expense due to solvent costs; and, if injected solvent is to be recovered and/or recycled, additional surface processing apparatus may be needed.

[0007] Commercial applications of both solvent-aided and solvent-based recovery processes have been limited to date. Challenges remain in providing solvent-aided and solvent-based recovery processes for efficient and effective commercial application.
Summary

[0008] According to an aspect of an embodiment, there is provided a process for recovering hydrocarbons from a subterranean hydrocarbon-bearing formation.

The process includes injecting an injection fluid into the hydrocarbon-bearing formation through an injection well including a substantially horizontal injection section in the hydrocarbon-bearing formation, and producing hydrocarbons from the hydrocarbon-bearing formation to a surface through a first production well including a substantially horizontal production section in the hydrocarbon-bearing formation. The injection section of the injection well is laterally offset from the production section of the first production well, and the injection well includes a side well extending substantially horizontally from the injection section toward a location along the production section or the production well includes the side well extending substantially horizontally from the location along production section toward the injection section. The process also includes selectively heating a region of the hydrocarbon-bearing formation that is near the location along the production section and vertically spaced from the first production well.

[0009] According to another aspect of an embodiment, a system for recovery of hydrocarbons from a subterranean hydrocarbon-bearing formation is provided.

The system includes a first production well including a substantially horizontal production section extending in the hydrocarbon-bearing formation for producing hydrocarbons from the hydrocarbon-bearing formation to a surface, and an injection well including a substantially horizontal injection section laterally offset from the production section of the first production well and extending in the hydrocarbon-bearing formation. The injection well includes spaced apart side wells extending substantially horizontally from the injection section toward respective spaced apart locations along the production section of the first production well, for injecting a fluid into the hydrocarbon-bearing formation , or the first production well includes the spaced apart side wells extending substantially horizontally from respective spaced apart locations along the production section toward the injection section for the flow of hydrocarbons into the first production well. The system also includes a substantially horizontal heating well spaced vertically from the production section. The substantially horizontal heating well is configured to selectively heat regions of the hydrocarbon-bearing formation that are near the spaced apart locations along the production section.
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. 1A is a schematic sectional view of a reservoir and shows the relative location of an injection well and a production well laterally spaced from the injection well;

[0012] FIG. 16 is a schematic sectional view of a reservoir and shows the relative location of an injection well, a production well laterally spaced from the injection well, and a third, heating well disposed generally vertically above the production well;

[0013] FIG. 2 is a schematic view of a reservoir and shows relative locations of an injection well and production wells laterally spaced from the injection well;

[0014] FIG. 3 is a flowchart showing a process for producing hydrocarbons from a subterranean hydrocarbon-bearing reservoir according to an embodiment;

[0015] FIG. 4 is a schematic sectional view of a reservoir and shows the relative location of an injection well, a production well laterally spaced from the injection well, and a third, heating well disposed generally vertically above the production well;

[0016] FIG. 5A, FIG. 56, FIG. 5C, and FIG. 5D illustrate simulations of solvent chamber growth after 1 year, 2 years, 3 years, and 5 years of production, respectively, according to one example in which no targeted heating is carried out;

[0017] FIG. 6A, FIG. 66, FIG. 6C, and FIG. 6D illustrate simulations of solvent chamber growth after 1 year, 2 years, 3 years, and 5 years of production, respectively, according to an example in which targeted heating is carried out in accordance with an embodiment;

[0018] FIG. 7A is a graph illustrating a simulation of production rate over time for a process without targeted heating and a process with targeted heating in accordance with an embodiment;

[0019] FIG. 76 is a graph illustrating a simulation of total production over time for a process without targeted heating and a process with targeted heating in accordance with an embodiment;

[0020] FIG. 8 is a graph illustrating a simulation of production rate over time for a SAGD process;

[0021] FIG. 9A is a bar chart illustrating total time to 60% recovery of hydrocarbons in reservoir simulations for three different processes;

[0022] FIG. 98 is a bar chart illustrating energy required for recovery of hydrocarbons in reservoir simulations for the processes of FIG. 9A;

[0023] FIG. 9C is a bar chart illustrating equivalent steam to oil ratio (eSOR) in reservoir simulations for the processes of FIG. 9A.
Detailed Description

[0024] 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.

[0025] The disclosure generally relates to a system and process for recovering hydrocarbons from a subterranean hydrocarbon-bearing formation. The process includes injecting an injection fluid into the hydrocarbon-bearing formation through an injection well including a substantially horizontal injection section in the hydrocarbon-bearing formation, and producing hydrocarbons from the hydrocarbon-bearing formation to a surface through a first production well including a substantially horizontal production section in the hydrocarbon-bearing formation.
The injection section of the injection well is laterally offset from the production section of the first production well and the injection well includes a side well extending substantially horizontally from the injection section toward a location along the production section. The process also includes selectively heating a region of the hydrocarbon-bearing formation that is near the location along the production section and vertically spaced from the first production well.

[0026] Referring to the schematic view of FIG. 1A, an example of an injection well 102 and a production well 104 in a reservoir 106 is illustrated. The production well 104 includes a generally vertical production section 108 that extends from the surface to a heel 110 of the production well 104, and a substantially horizontal production section 112 that extends from the heel 110, generally horizontally into the reservoir 106. It will be appreciated that the reservoir base is not uniform. In the present example, the production well 104 is a multilateral well.

[0027] The substantially horizontal production section 112 shown in FIG.
1A is one lateral of the production well 104 and is utilized for producing fluid, including hydrocarbons from the reservoir 106. A second lateral 114 extends generally parallel to and is spaced vertically above the first lateral that includes the substantially horizontal production section 112. The second lateral 114 is utilized for targeted heating to heat regions of the reservoir, by applying heat at positions along the second lateral 114, that are vertically spaced from the horizontal production section 112.

[0028] Throughout the present description, the targeted heating is applied along the second lateral 114 of the production well 104. Referring to FIG. 1B, another embodiment is illustrated in which a production well 104 is laterally spaced from the injection well 102, and a third well 105, utilized for heating, is disposed generally vertically above the production well 102. Rather than selectively heating utilizing a lateral of the production well, the heating may be selectively applied along the third well 105 spaced from the production well 104 such that a substantially horizontal section 115 of the third well 105 is vertically spaced from the horizontal production section 112. Thus, the third well 105 may be utilized for the selective heating throughout the present description, rather than the lateral of the production well.

[0029] Referring again to FIG. 1A, the injection well 102 also includes a generally vertical injection section 116 that extends from the surface to a heel 118 of the injection well 102, and a substantially horizontal injection section 120 that extends from the heel 118, generally horizontally into the reservoir 106 and parallel to the horizontal production section 112 of the production well 104. The horizontal injection section 120 is spaced horizontally from the horizontal production section 112. The spacing between the horizontal injection section 120 and the horizontal production section 112 may be about 25 meters to about 200 meters. For example, the horizontal injection section 120 may be laterally spaced about 50 meters from the horizontal production section 112. The horizontal injection section 120 is not vertically offset from the horizontal production section 112, i.e., the horizontal injection section 120 and the horizontal production section 112 generally lie on a same horizontal plane. It will be appreciated, however, that the horizontal injection section 120 and the horizontal production section 112 are not perfectly horizontal or perfectly parallel to each other given that there may be variations in the direction along the well paths.

[0030] The injection well 102 includes a side well 122 (sometimes referred to as a side track) that extends substantially horizontally from the horizontal injection section 120, toward a location along the horizontal production section 112. In the present example, three side wells 122 are shown extending from the horizontal injection section 120 toward respective locations along the horizontal production section 112. Any suitable number of side wells 122 may be utilized and the side wells 122 in this example are spaced at regular intervals along the horizontal injection section 120. The number of side wells 122 and location of side wells may be dependent on the reservoir geology.

[0031] The number of side wells 122 may be based on the length of the horizontal injection section 120. For example, the side wells 122 may be spaced about 100 m to about 200 m apart along the length of the horizontal injection section 120. Thus, for example, 8 side wells, extending toward one substantially horizontal production section 112 of a production well 108, may be utilized for an 800 meter long horizontal injection section 120. The side wells 122 extend generally parallel to each other, to locations near the horizontal production section 112. The side wells 122 may extend to within up to about 5 m from the horizontal production section 112. The side wells 122 may, optionally, be connected to the horizontal production section 112. Drilling technologies may make connection of the side wells 122 to horizontal production section 112 difficult or unlikely.
The side wells 122, therefore, may not be directly connected to the horizontal production section 112 and may extend to within about 1 m to about 5 m from the horizontal production section. For example, it will be appreciated that the side wells may not extend perfectly perpendicular from the horizontal injection section 120 as such side wells may be slightly curved as a result of drilling techniques employed.
The side wells 122 may be drilled starting off in a curve. As a result, the side wells 122 may extend at an angle from the horizontal injection section. For example, the side wells 122 may extend at an angle of greater than 90 from the horizontal injection section 120.

[0032] In addition, another 8 side wells may extend toward a second substantially horizontal production section of a second production well. The additional 8 side wells extend generally opposite in direction to the first 8 side wells 122, and are parallel to each other, extending to locations near the second horizontal production section but not directly connected to the second horizontal production section. The second side wells may extend to within about 1 m to about m from the second horizontal production section. Thus, the second 8 side wells generally mirror the first 8 side wells 122 referred to above.

[0033] The injection well 102 is utilized for injecting a fluid, such as solvent in gaseous form, i.e., a solvent vapor, into the reservoir 106. Flow control devices or an injection tubing with open ports may be utilized to generally evenly distribute the solvent along the length of the injection well 102 and into the side wells 122.
The side wells 122 are perforated in this example (shown with dotted lines) for the purpose of injecting fluid into the reservoir 106. The fluid is therefore injected through the side wells 122, into the reservoir 106, and near the production well 104. The side wells 122 may optionally be cased multilateral, cased open hole or uncased open hole. A solvent chamber is established along the side wells 122 and grows generally parallel to the injection well 102 and production well 104.

[0034] The positions at which heat is selectively applied along the second lateral 114 are based on the locations along the horizontal production section near to which the side wells 122 extend. For example, the positions at which heat is applied along the second lateral 114 may be proximal to the locations along the horizontal production section 112, and downstream therefrom, also referred to as uphole or closer to the heel 110 of the production well 104.

[0035] Heat is selectively applied at locations along the second lateral and proximal to the locations along the horizontal production section 112, and downstream therefrom, reducing the chance that vapors are generated and carried back to a production well pump. Selectively heating from within the horizontal production section 112 may generate vapors that are carried back to the production well pump and may degrade efficiency by comparison to a process in which heating is carried out outside the horizontal production section 112 of the production well 104.

[0036] The heat may be selectively applied by electrical and/or non-electrical heating, for example induction heating, infrared heating, radio-frequency heating, electro-magnetic heating, microwave heating, circulating hot fluid, or any other suitable method. For example, the heat may be selectively applied utilizing, for example, a resistive heater disposed in the second lateral 114. Alternatively, heat may be applied by injecting steam into the second lateral 114, for example, at a relatively low rate of 2 tons/day compared to SAGD in which steam may be injected at, for example, 300-400 tons/day. Insulated tubing and optionally flow control devices may be selectively utilized along the second lateral 114 to selectively apply the heat by injecting steam.

[0037] In the examples described with reference to FIG. 1A and FIG. 1B, a single production well 104 and single injection well 102 are shown. More than one production well may be utilized. Similarly, more than one injection well may be utilized. FIG. 2 shows an example in which a respective production well 104 is located on either side of the injection well 102. For the purpose of clarity of illustration, only the horizontal production sections 112 and the horizontal injection section 120 are shown. The horizontal production sections 112 and the horizontal injection section 120 are all generally parallel and are located on a same horizontal plane. For the purpose of the present example, each horizontal production section 112 is about 50 meters from the horizontal injection section 120. In this example, the side wells 122 extend generally perpendicularly from the horizontal injection section 120 toward both horizontal production sections 112. The side wells 122 need not extend perpendicularly toward the horizontal injection section 120, as the side wells 122 may extend from the horizontal injection section at angles greater than 900 or any other angle varying from 90 that may be drilled and completed more easily utilizing drilling and completion techniques.

[0038] A process for producing hydrocarbons from a subterranean hydrocarbon-bearing formation is shown in FIG. 3. The process may include additional or fewer elements than shown and described and, the elements of the process may be carried out simultaneously or in a different order than that shown in FIG. 3. The process may be carried out in a formation such as the reservoir described with reference to FIG. 1A or FIG. 1B.

[0039] A start-up procedure is first carried out to establish fluid communication between the injection well 102 and the adjacent production well or production wells 104. Any suitable start-up procedure may be utilized, such as for example hot fluid (e.g., steam or hot water) wellbore circulation, the use of selected solvents such as xylene (as, for example, described in CA 2,698,898 to Pugh, et al.), the application of geomechanical techniques such as dilation (as, for example, described in CA 2,757,125 to Abbate, et al.), the use of surfactants (as,for example, described in CA 2,886,934 to Zeidani), 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, in CA 2,831,928 to Bracho Dominguez, et al.) A
start-up procedure may utilize steam, solvent, heater(s), or a combination thereof.
More than one start-up procedure may be utilized to establish fluid communication.

[0040] In this example, fluid is injected through the injection well 102 at 302.
The fluid may include a mixture of solvent, non-condensable gas (NCG), such as methane (or natural gas), and steam injected into the injection well 102 and into the reservoir 106 via the side wells 122. The mixture of solvent, non-condensable gas, and steam may be injected into the injection well 102 continuously until fluid communication is established between the injection well 102 and the adjacent production well 104 or production wells 104. NCGs include, but are not limited to air, nitrogen, carbon dioxide, methane, natural gas, other light hydrocarbons, or a combination thereof. The non-condensable gas may facilitate maintaining at least a portion of the solvent in the vapor phase due to a partial pressure effect, allowing the solvent to travel further before completely condensing. This is beneficial in maintaining the side wells 122 open while a steam/solvent chamber is established.

[0041] The start-up procedure may include electrically heating the side wells 122 utilizing, for example, electrical heating elements, in addition to or rather than utilizing steam.

[0042] After fluid communication is established, an injection fluid comprising a solvent may be injected, for example a single solvent or a mixture of solvents.
Any suitable solvent that vaporizes with little additional energy input may be utilized. The solvent may be injected as a liquid for a relatively short period of time as the heat in the reservoir resulting from startup is utilized to vaporize the solvent.
The heat from start-up, however, may not be sufficient to sustain solvent vaporization for a long period of time. The vapor phase facilitates solvent propagation along the side wells. Solvents that vaporize easily at reservoir conditions are preferable. The temperature of the solvent is affected by the pressure and thus the solvent temperature may be dependent on the depth of the reservoir. For example, propane, butane, or a combination thereof, may be injected at a temperature at or above the dew point of the solvent. In a particular example, propane is injected at a temperature of 100 C. This temperature may be dependent on the conditions of the particular reservoir and properties of the solvent mixture. The solvent vapor contacts the hydrocarbons, which may be bitumen, in the reservoir 106 and condenses. The solvent serves to dissolve an oleic phase, reducing the viscosity and mobilizing the oleic phase. A heavier solvent (C5 to C10) may be added, e.g., up to about 10 wt%, to create a mixture with a lighter solvent such as propane, butane, or a combination thereof, to help preferentially condense the lighter solvent(s) in the side wells, which may help keep the side wells from being plugged by solid bitumen. A pressure gradient between the injection well 102 and the production well 104 or production wells 104 facilitates the flow of fluids towards and into the production well 104. For example, a pressure gradient of about 50 kPa to about 200 kPa over a 100 m injector-producer well spacing may be employed to drive gaseous flow from the injection well 102 to the production well 104. The mobilized hydrocarbons move toward the production well 104 and are produced to the surface at 304 through the production well 104.

[0043] Targeted heating is carried out at 306 by selectively heating at targeted positions along the second lateral 114 of the production well 104.
Alternatively, targeted heating may be carried out utilizing one or more separate wells or laterals drilled into the reservoir, rather than a second lateral 114 of the production well 104. The heating may be carried out utilizing any suitable heat source. For example, a resistive heating element may be utilized in the second lateral 114. Alternatively, steam may be injected to the targeted positions along the second lateral. As indicated above, the positions at which heat is applied along the second lateral 114 may be proximal to the locations along the horizontal production section 112 near to which the side wells 122 extend, and downstream therefrom, also referred to as uphole or closer to the heel 110 of the production well 104. For example, the heat may be applied within about 10 m of the nearest side well 122. The heat may be applied at a vertical distance of, for example, about 2 m to about 10 m to the nearest side well. The heating is , however, spaced, generally horizontally, uphole to reduce the chance of back pressure that may be created as a result of heating and vaporization occurring horizontally close to the nearest side well.

[0044] Optionally, targeted heating may be carried out for all production wells of a pad or may be carried out for less than all of the production wells of the pad such that targeted heating is not carried out for one or more production wells. The production wells at which selective heating is applied may be dependent on conformance and reservoir characteristics.

[0045] The amount of heat applied may be a function of the volume of condensed solvent flowing at or near the locations along the horizontal production section 112 near to which the side wells 122 extend and may depend on reservoir properties such as heterogeneities.

[0046] Thus, heat is targeted to positions in close proximity to the location of the side wells 122. Utilizing this targeted heating, solvent that is injected via the side wells 122 and that is condensed in the formation, flows toward the production well 104 and is re-vaporized, establishing a secondary solvent chamber. Re-vaporization allows the condensed solvent to once again transfer latent heat to bitumen and hence increase recovery rates. The volume of solvent that is recycled is reduced, and may facilitate a reduction in the size of a surface solvent separation facility. In addition, the solvent chamber may grow more quickly along the length of the horizontal production section 112 by comparison to a similar process without targeted heating.

[0047] The solvent that is produced along with the hydrocarbons is optionally separated from the remainder of the produced fluid at the well pad or at a central surface solvent separation facility at 308 and the solvent may be reused.

[0048] In a later stage of oil production, the hydrocarbon recovery operation may enter an ending or winding down blowdown phase. The blowdown phase may be performed in a similar manner as in a conventional SAGD process; however, the blowdown phase may be initiated sooner because of the improved rate at which oil is produced from the formation. During the blowdown phase, a NCG may be injected into the reservoir to replace the solvent. For example, the NCG may be methane. Alternatively, in an embodiment, the solvent(s) used for injection may be continuously utilized through a blowdown phase, in which case it is possible to eliminate or reduce injection of methane during blowdown. It may not be necessary to implement a conventional blowdown phase with injected methane when a significant portion of the injected solvent can be readily recycled and reused.

[0049] Because the horizontal injection section 120 is not vertically offset from the horizontal production section 112, the process may be implemented for shallow pay zones of, for example about 5 m to about 10 m, in which insufficient space is available for processes such as SAGD.

[0050] In the examples described above with reference to FIG. 1A, FIG. 1B, and FIG. 2, the injection well 102 includes the generally vertical injection section 116, a substantially horizontal injection section 120, and side wells 122 that extend generally horizontally from the horizontal injection section 120, toward a location along the horizontal production section 112. Rather than the side wells 122 extending from the horizontal section 120 of the injection well 102 and toward the horizontal production section 112, side wells may alternatively extend from the horizontal production section of the production well toward the horizontal injection section of the injection well, as illustrated in the example of FIG. 4. The spacing between the horizontal injection section 420 and the horizontal production section 412 may be similar to that described above with reference to FIG. 1A and FIG.
1B.

[0051] The side wells 422, in this alternative embodiment, extend generally parallel to each other, to respective locations near the horizontal injection section 420 of the injection well 402. Any suitable number of side wells 422 may be utilized and the number of side wells 122 and location of side wells 422 may be dependent on the reservoir geology. The side wells 422 may not be directly connected to the horizontal injection section 420 and may extend to within about 1 m to about 5 m from the horizontal injection section 420.

[0052] Further side wells may also extend toward a second substantially horizontal injection section of a second injection well.

[0053] The injection well 402 is utilized for injecting a fluid, such as solvent in gaseous form, i.e., a solvent vapor, into the reservoir. Flow control devices or an injection tubing with open ports may be utilized to generally evenly distribute the solvent along the length of the injection well 402. Mobilized hydrocarbons move toward the side wells and into the production well 404 and are produced to the surface 4 through the production well 404.

[0054] The positions at which heat is selectively applied along the third well 405 or second lateral are based on the locations along the horizontal production section 412 from which the side wells 422 extend. For example, the positions at which heat is applied along the third well 405 or second lateral may be proximal to the locations along the horizontal production section 412, and downstream therefrom, also referred to as uphole or closer to the heel of the production well 404.

[0055] According to yet another example embodiment, a cross-well system may be utilized rather than the generally parallel injection wells and production wells. In such a cross-well system, horizontal sections of the injection wells may be oriented generally perpendicularly to the horizontal production section and may be spaced vertically therefrom. Because of the orientation of the injection wells, each injection well may extend over horizontal production sections of several production wells. The injection wells may include perforated sections along the injection wells to facilitate injection of fluids at targeted locations into the chamber in the hydrocarbon-bearing formation.

[0056] The third wells or lateral wells extending generally parallel with the production wells are utilized for targeted heating to heat regions of the reservoir by applying heat at positions along the third wells or production wells that are spaced from respective horizontal production sections of several production wells.

[0057] According to yet another example of an embodiment, the third wells or lateral wells may extend generally perpendicular to the horizontal production sections of the production wells such that each well extends for targeted heating at locations along horizontal production section of several horizontal production wells.

[0058] Rather than utilizing a third well or lateral well, targeted heating may be effectuated utilizing a heat trace elements on an outside of the production well casing. In another alternative, heat trace elements may be included in the production well, in a production tubing, for example. Thus, a third well or lateral well need not be drilled. The trace elements may be wired and controlled independently to independently control heating at targeted locations.

[0059] To demonstrate the present process and understand the process mechanisms, simulations were conducted. The simulation models included side wells, such as the side wells 122 at 100 m intervals along a horizontal injection section 120.

[0060] FIG. 5A, FIG. 5B, FIG. 5C, and FIG. 5D illustrate solvent chamber growth after 1 year, 2 years, 3 years, and 5 years of hydrocarbon production, respectively, in a simulation without targeted heating. The front bottom edge of the half-symmetry simulation represents the production well. FIG. 6A, FIG. 6B, FIG.
6C, and FIG. 6D illustrate solvent chamber growth after 1 year, 2 years, 3 years, and 5 years of hydrocarbon production, respectively, in a simulation with targeted heating. The targeted heating was selectively applied about 10 m downstream from the location along the production well that was closest to the nearest side well. The darker areas in FIG. 5A through FIG. 6D represent the volume from which oil was produced.

[0061] FIG. 5D illustrates solvent chamber growth after 5 years of production without targeted heating, while FIG. 6D illustrates solvent chamber growth after 5 years of production with targeted heating, in accordance with an embodiment of the present disclosure. A comparison of FIG. 5D and FIG. 6D, shows that the targeted heating resulted in significantly faster solvent chamber growth along the length of the horizontal production section as indicated by a greater portion of darker areas in FIG. 6D compared to FIG. 5D.

[0062] Simulation results show that each side well created its own solvent chamber which performed independently of other solvent chambers prior to the solvent chambers merging at a later time in the process. Without being limited to theory, the production performance of the process may be a function of the number of side wells implemented along the horizontal production section.

[0063] FIG. 7A shows the hydrocarbon production rate over time per side well for the simulation without targeted heating and the simulation with targeted heating. FIG. 7B shows the total hydrocarbon production over time per side well for the simulation without targeted heating and the simulation with targeted heating. As illustrated by FIG. 7A and FIG. 7B, the rate of production of hydrocarbons and the total produced hydrocarbons were improved with targeted heating.

[0064] FIG. 8 shows the production rate over time for a SAGD process simulation. A comparison of FIG. 7A and FIG. 8, shows that the production rate over time for the SAGD process declined rapidly after 500 days. The production rate per side well of the simulation with targeted heating was generally consistent.

[0065] The total time to 60% recovery of hydrocarbons in a reservoir simulation comparing SAGD, solvent injection without targeted heating, and solvent injection with targeted heating is illustrated in FIG. 9A. The results indicated that time to 60% recovery was longest for SAGD at 8 years and was shortest for solvent injection with targeted heating at 3.6 years.

[0066] The total energy utilized to reach 60% recovery of hydrocarbons for the three reservoir simulations of FIG. 9A is illustrated in FIG. 9B. The energy requirement was greatest for SAGD at 1.2 GJ per barrel (bbl) of oil produced.
The energy required for solvent injection with targeted heating in accordance with an embodiment of the present disclosure was slightly higher at 0.31 GJ/bbl than without targeted heating at 0.29 GJ/bbl. Solvent injection with and without targeted heating were both less energy intensive than in the SAGD simulation.

[0067] The equivalent steam to oil ratio (eSOR) for the three reservoir simulations of FIG. 9A is illustrated in FIG. 9C. The eSOR is determined for processes in which steam is not injected after start-up by converting the total energy input to the process into equivalent barrels of steam. The steam to oil ratio was highest in the SAGD simulation, requiring 2.3 bbl of steam to produce 1 bbl of oil. Utilizing the process of the present disclosure, the eSOR was reduced compared to SAGD by about 70% to about 0.7 equivalent barrels of steam required to produce 1 bbl of oil. In accordance with the present disclosure, the eSOR was only slightly higher in the simulation where solvent was injected with targeted heating (eSOR 0.74) compared to without targeted heating (eSOR 0.69). Utilizing targeted heating, higher oil production rates were realized; therefore, on a volume of produced hydrocarbon basis, the eSOR was similar to that for a process without targeted heating.

[0068] Large volumes of steam produced may be problematic for equipment, such as pumps utilized in the production well, and may result in lower production rates. In the process of the present disclosure, solvent vapor may condense more quickly and be primarily produced back in the liquid phase. This may facilitate operation of the pump at higher production rates compared to SAGD or other hydrocarbon recovery processes involving steam (e.g., cyclic steam stimulation (CSS), expanding solvent steam-assisted gravity drainage (ES-SAGD), steam flooding, solvent-assisted cyclic steam stimulation, or a solvent-aided process (SAP)).

[0069] In accordance with the present disclosure, the recovery of hydrocarbons is primarily a gravity driven process with a small convective gradient from the injection well 102 to the production well 104. Oil and condensed solvent drain downwardly due to gravity, while vapors are swept from the injector towards the producer by the convection (due to the pressure gradient). The low resistance path provided by the side well(s) facilitates fluid flow towards the production well.

[0070] The solvent chamber is established along the side well or side wells 122 and grows generally parallel to the injection well 102 and production well 104.
Post start-up, water produced via the production well 104 may be mainly from connate water found in the reservoir 106, which is a small fraction of the water produced during a SAGD process. Thus, less water is produced and subjected to separation from the produced hydrocarbons, which may result in a smaller surface oil-water separation facility footprint.

[0071] As described above, hydrocarbon production utilizing the process of FIG. 3 is dependent on the number of side wells 122 drilled. Production may be significantly accelerated by drilling more side wells 122.

[0072] In the above description, a multilateral production well or a third well is utilized for selectively heating regions near the locations as which the side wells approach the production well. Rather than utilizing a lateral of the production well or a third well, hot fluid, such as steam or hot water, may be periodically injected into the injection well or the production well. Thus, injection or production is periodically stopped and the hot fluid allowed to soak into the reservoir before restarting the injection or production. This alternative heating option may involve low rate steam or hot water circulation in production wells that may optionally utilize insulated tubing. Optionally, a periodic steam slug may be injected into the production or injection wells.

[0073] The periodic stopping of injection or production and injection of hot fluid may be advantageous without requiring an additional lateral or third well to be drilled. Providing time for the hot fluid to soak may be beneficial in reducing the chance of vapors generated being carried back to a production well pump.

[0074] Advantageously, the process of the present application provides improved energy efficiency over other processes. The process as illustrated and described herein may be utilized in, for example, thin reservoirs in which SAGD is not viable. Hydrocarbon recovery from reservoirs previously considered to have marginal pays, more complex heterogeneities, and thicknesses varying from about m to about 10 m may be carried out. Thus, the process may be implemented for shallow pay zones, in which insufficient space is available for processes such as SAGD and, in turn, in which a steam chamber would need to be established.

[0075] In the case of more geologically complex reservoirs containing heterogeneities, including but not limited to clasts, bridges, baffles, low permeability regions and barriers (e.g., mud barriers), the solvent process(es) of the present disclosure may provide enhanced performance compared to SAGD even if performance is diminished somewhat as the injection fluid flows against and/or around such heterogeneities between the injection well and the production well.
Such enhancement may be possible due to the horizontal sweep of fluid(s) through the reservoir by the imposed pressure gradient from injector to producer compared to the vertical gravity drainage relied upon in SAGD.

[0076] 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 (35)

Claims

1. A process for recovering hydrocarbons from a subterranean hydrocarbon-bearing formation, the process comprising:
injecting an injection fluid into the hydrocarbon-bearing formation through an injection well including a substantially horizontal injection section in the hydrocarbon-bearing formation;
producing hydrocarbons from the hydrocarbon-bearing formation to a surface through a first production well including a substantially horizontal production section in the hydrocarbon-bearing formation, wherein the injection section of the injection well is laterally offset from the production section of the first production well and the injection well includes a side well extending substantially horizontally from the injection section toward a location along the production section or the production well includes the side well extending substantially horizontally from the location along production section toward the injection section; and selectively heating a region of the hydrocarbon-bearing formation that is near the location along the production section and vertically spaced from the first production well.

2. The process according to claim 1, wherein selectively heating the region comprises heating proximal to, and downstream from the location along the production section.

3. The process according to claim 1, wherein selectively heating comprises selectively heating the region utilizing a lateral of the first production well, which lateral extends generally parallel with the horizontal production section.

4. The process according to claim 1, wherein selectively heating comprises selectively heating the region utilizing a third well spaced from the first production well.

5. The process according to claim 1, wherein selectively heating comprises selectively heating the region utilizing electric heat tracers associated with the production well.

6. The process according to claim 1, wherein a pressure gradient is formed between the injection well and the first production well to facilitate the flow of fluids toward the first production well.

7. The process according to claim 1, wherein the injection well includes a plurality of spaced apart side wells, including the side well, extending substantially horizontally from the injection section toward respective locations along the production section, including the location along the production section, and the process comprises selectively heating a plurality of regions of the hydrocarbon-bearing formation, including the region of the hydrocarbon-bearing formation, that are near the locations along the production section and vertically spaced from the first production well.

8. The process according to claim 1, wherein the production well includes a plurality of spaced apart side wells, including the side well, extending substantially horizontally from respective locations, including the location, along the production section toward the injection section, and the process comprises selectively heating a plurality of regions of the hydrocarbon-bearing formation, including the region of the hydrocarbon-bearing formation, that are near the locations along the production section and vertically spaced from the first production well.

9. The process according to claim 7 or claim 8, wherein the plurality of side wells are generally parallel to each other and wherein selectively heating the plurality of regions comprises selectively heating proximal to, and downstream from the respective locations along the production section.

10. The process according to claim 9, wherein selectively heating comprises selectively heating the plurality of regions utilizing a lateral of the first production well, which lateral extends generally parallel with the horizontal production section.

11. The process according to claim 7 or claim 8, wherein the side wells are spaced about 100 meters to about 200 meters apart.

12. The process according to claim 7 or claim 8, wherein selectively heating comprises applying heat near the respective locations along the horizontal production section and uphole therefrom by 2 meters to 10 meters from each of the respective locations.

13. The process according to claim 6, wherein the side wells extend toward the production section within a distance of from 1 meter to 5 meters of the production section.

14. The process according to claim 1, wherein the injection section is spaced from the production section by a distance of from 25 meters to 200 meters.

15. The process according to claim 1, wherein injecting an injection fluid comprises injecting a solvent.

16. The process according to claim 15, wherein the solvent comprises at least one of propane, butane, and a combination of propane and butane.

17. The process according to claim 15, wherein a solvent chamber is established along the side well and grows generally parallel to the injection section and the production section.

18. The process according to claim 1, wherein injecting an injection fluid comprises injecting a solvent vapor.

19. The process according to claim 18, wherein selectively heating comprises re-vaporizing the solvent after the solvent condenses to establish a secondary solvent chamber.

20. The process according to claim 1, wherein selectively heating comprises resistive heating.

21. The process according to claim 1, wherein selectively heating comprises locating a resistive heater along a lateral of the first production well, which lateral extends generally parallel with the horizontal production section.

22. The process according to claim 1, wherein selectively heating comprises injecting steam into a lateral of the first production well, which lateral extends generally parallel with the horizontal production section.

23. The process according to claim 1, comprising:
producing hydrocarbons from a second production well including a substantially horizontal second production section in the hydrocarbon-bearing formation, wherein the second production section of the second production well is laterally offset from the injection section of the injection well and disposed on an opposite side of the injection section as the production section of the first production well such that the injection section is generally between the production section of the first production well and the second production section;
wherein the injection section includes:
a plurality of first side wells, including the side well, extending substantially horizontally from the injection section toward respective first locations along the production section of the first production well;

a plurality of second side wells extending substantially horizontally from the injection section toward respective second locations along the second production section;
wherein selectively heating the region comprises selectively heating first regions of the hydrocarbon-bearing formation that are near the first locations along the production section of the first production well and vertically spaced from the first production well; and selectively heating second regions of the hydrocarbon-bearing formation that are near the second locations along the second production section and vertically spaced from the second production well.

24. The process according to claim 1, comprising establishing fluid communication between the injection well and the first production well by injecting a mixture of solvent, non-condensable gas, and steam into the injection well prior to injecting the injection fluid. .

25. A system for recovery of hydrocarbons from a subterranean hydrocarbon-bearing formation, the system comprising:
a first production well including a substantially horizontal production section extending in the hydrocarbon-bearing formation for producing hydrocarbons from the hydrocarbon-bearing formation to a surface;
an injection well including a substantially horizontal injection section laterally offset from the production section of the first production well and extending in the hydrocarbon-bearing formation, wherein the injection well includes spaced apart side wells extending substantially horizontally from the injection section toward respective spaced apart locations along the production section of the first production well, for injecting a fluid into the hydrocarbon-bearing formation, or the first production well includes the spaced apart side wells extending substantially horizontally from respective spaced apart locations along the production section toward the injection section for the flow of hydrocarbons into the first production well;
a substantially horizontal heating well spaced vertically from the production section, the substantially horizontal heating well configured to selectively heat regions of the hydrocarbon-bearing formation near the spaced apart locations along the production section.

26. The system according to claim 25, wherein the heating well includes a heater for selectively heating the regions of the hydrocarbon-bearing formation.

27. The system according to claim 25, wherein the heating well includes insulated tubing utilized along portions of the heating well to selectively apply the heat by injecting steam.

28. The system according to claim 25, wherein the heating well is a lateral well extending from the first production well.

29. The system according to claim 25, wherein the heating well is a third well spaced from the first production well.

30. The system according to claim 25, wherein the injection section is spaced from the production section by a distance of from 25 meters to 200 meters.

31. The system according to claim 25, wherein the side wells are spaced apart by about 100 meters to 200 meters.

32. The system according to claim 25, wherein the side wells extend toward the production section, within a distance of from 1 meter to 5 meters of the production section.

33. The system according to claim 25, wherein the heating well is configured to apply heat near the locations along the horizontal production section and downstream therefrom by 5 meters to 10 meters from each of the locations.

34. A process for producing hydrocarbons from a subterranean hydrocarbon-bearing formation, the process comprising:
injecting an injection fluid into the hydrocarbon-bearing formation through injection wells, each including a generally horizontal injection section in the hydrocarbon-bearing formation;
producing hydrocarbons from the hydrocarbon-bearing formation to a surface through production wells, each including a substantially horizontal production section in the hydrocarbon-bearing formation, wherein the injection sections of the injection wells are vertically offset from the production sections of the production wells and extend generally perpendicular to the production sections, the injection sections include openings for the injection of fluids into the hydrocarbon-bearing formation at targeted locations between adjacent production sections;
selectively heating regions of the hydrocarbon-bearing formation that are near the targeted locations between the adjacent production sections.

35. The process according to claim 34, wherein selectively heating comprises heating utilizing electric tracers associated with the production sections.