CA2847759A1

CA2847759A1 - A method of enhancing resource recovery from subterranean reservoirs

Info

Publication number: CA2847759A1
Application number: CA2847759A
Authority: CA
Inventors: Rahman Khaledi
Original assignee: Imperial Oil Resources Ltd
Current assignee: Imperial Oil Resources Ltd
Priority date: 2014-03-28
Filing date: 2014-03-28
Publication date: 2015-09-28
Anticipated expiration: 2034-03-28
Also published as: CA2847759C

Abstract

A method of recovering heavy oil from a subterranean reservoir includes providing an infill well, injecting injected fluid via an infill well, producing produced fluid from the infill well and producing heavy oil from at least one of the infill well and a production well. The infill well may be placed in an area laterally spaced apart from a thermal recovery well pair. The thermal recovery well pair may include an injection well for injecting injection vapor to form a vapor chamber and the production well. The injected fluid may be injected at a time during which the injected fluid establishes a horizontal planar communication path between the infill well and the vapor chamber. The horizontal planar communication path enables generally horizontal planar distribution of the injection vapor to provide horizontal planar communication. The produced fluid at least partially removes heavy oil from the horizontal planar communication path.

Description

, , A METHOD OF ENHANCING RESOURCE RECOVERY FROM SUBTERRANEAN RESERVOIRS
FIELD
[0001] The present disclosure relates to recovering resources using thermal recovery processes. Specifically, the present disclosure relates to enhancing recovery of heavy oil using thermal recovery processes or techniques.
BACKGROUND

[0002] This section is intended to introduce various aspects of the art. This discussion is believed to facilitate a better understanding of particular aspects of the present techniques.
Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

[0003] Modern society is greatly dependent on the use of hydrocarbon resources for fuels and chemical feedstocks. Subterranean rock formations that can be termed "reservoirs" may contain resources, such as hydrocarbons, that can be recovered. Removing hydrocarbons from the subterranean reservoirs depends on numerous physical properties of the subterranean rock formations, such as the permeability of the rock containing the hydrocarbons, the ability of the hydrocarbons to flow through the subterranean rock formations, and the proportion of hydrocarbons present, among other things.

[0004] Easily produced sources of hydrocarbons are dwindling, leaving less conventional sources to satisfy future needs. As the costs of hydrocarbons increase, less conventional sources become more economical. One example of less conventional sources becoming more economical is that of oil sand production. The hydrocarbons produced from less conventional sources may have relatively high viscosities, for example, ranging from 1000 centipoise (cP) to 20 million cP with American Petroleum Institute (API) densities ranging from 8 API, or lower, up to 20 API, or higher. The hydrocarbons recovered from less conventional sources may include heavy oil. However, the hydrocarbons, like heavy oil, produced from the less conventional sources are difficult to recover using conventional techniques.

,

[0005] Several methods have been developed to recover heavy oil from, for example, oil sands. Strip or surface mining may be performed to access oil sands. Once accessed, the oil sands may be treated with hot water or steam to extract the heavy oil. For subterranean reservoirs where heavy oil is not close to the Earth's surface, heat may be added and/or dilution may be used to reduce the viscosity of the heavy oil and recover the heavy oil from the subterranean reservoir. Heat may be supplied through a heating agent like steam. The heat may be injected into the subterranean reservoir via an injection well or wellbore. If the heating agent is steam, the steam may be condensed to water at the steam/cooler-oil-sands interface in the subterranean reservoir and supply latent heat of condensation to heat the heavy oil in the oil sands, thereby reducing viscosity of the heavy oil and causing the heavy oil to flow more easily. The heavy oil recovered from the subterranean reservoir may or may not be produced via a production well or wellbore. The production well or wellbore may be the same well or wellbore as the injection well or wellbore.

[0006] A number of thermal recovery processes or techniques for recovery of heavy oil have been developed. These processes or techniques may include, for example, cyclic steam stimulation or cyclic solvent stimulation (CSS), steam assisted gravity drainage (SAGD), vapor extraction process (VAPEX), steam flooding, in-situ combustion and thermal enhanced oil recovery and solvent-assisted steam assisted gravity drainage (SA-SAGD). These processes may be cyclic recovery processes in which there is intermittent injection of a mobilizing fluid to lower a viscosity of the heavy oil followed by recovery of the reduced viscosity heavy oil.

[0007] CSS techniques, that are cyclic steam stimulation techniques, use steam heat to lower the viscosity of the heavy oil. The steam is injected into the subterranean reservoir through a well that raises the temperature of the heavy oil during a heat soak phase, thus lowering the viscosity of the heavy oil. As the viscosity of the heavy oil is reduced, the heavy oil may flow down towards the well. The well may then be used to produce heavy oil from the subterranean reservoir. Solvents may be used in combination with steam in CSS
processes, such as in mixtures with the steam or in alternate injections between steam injections.
Exemplary CSS techniques are described in U.S. Patent No. 4,280,559, U.S.
Patent No.
4,519,454, and U.S. Patent No. 4,697,642.

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[0008] SAGD is a process where two horizontal wells (a well pair) are completed in a subterranean reservoir. The two wells may be first drilled vertically to different depths within the subterranean reservoir. Thereafter, using directional drilling technology, the two wells may be extended in a horizontal direction that results in two horizontal wells (i.e., a production well and an injection well), each vertically spaced from, but otherwise vertically aligned with, the other. Ideally, the production well may be located above the base of the subterranean reservoir but as close as practical to the bottom of the subterranean reservoir. A horizontal portion of the injection well may be located vertically above, such as, for example, 10 to 30 feet or 3 to 10 meters above, a horizontal portion of the production well. The injection well may be supplied with steam from a facility on the surface. The steam may rise from the injection well, permeating the subterranean reservoir to form a vapor chamber (ie., steam chamber) above the well pair. As the vapor chamber grows over time towards the top of the subterranean reservoir, the steam may condense at the steam/cooler-oil sands interface, releasing latent heat of steam, thereby reducing the viscosity of the heavy oil in the subterranean reservoir.
The heavy oil and condensed steam may then drain downward through the subterranean reservoir under the action of gravity and flow into the production well. After flowing into the production well, the heavy oil and condensed steam can be pumped to the surface. At the surface, the condensed steam and heavy oil may be separated, and the heavy oil may be diluted with appropriate light hydrocarbons for transportation by pipeline.
SAGD processes are described in Canadian Patent No. 1,304,287 and U.S. Patent No. 4,344,485.

[0009] Solvents may be used alone or in combination with steam in a SAGD or CSS
process. As the solvents blend with the heavy oil, the viscosity of the heavy oil decreases, thereby allowing the heavy oil to flow downwards toward a production well. The mobility of the heavy oil obtained with a steam and solvent combination may be greater than that obtained using steam alone under substantially similar formation conditions.

[0010] The subterranean reservoirs in which SAGD or CSS take place are generally composed of a reservoir matrix of rock having hydrocarbons, such as heavy oil, within a pore space of the reservoir matrix. In the SAGD process, the steam forming the vapor chamber above the SAGD well pair reduces the viscosity of the heavy oil within the vapor chamber and , enables the heavy oil to flow through the pore space of the reservoir matrix down into the production well. The vapor chamber has a generally triangular cross section with the production well and/or the injection well at an apex of this triangular shape.
This generally results in an area between vapor chambers of adjacent SAGD well pairs in which the heavy oil is not mobilized for recovery.

[0011] Processes combining SAGD and CSS have been proposed to recover bypassed heavy oil located between SAGD well pairs. In one such proposal disclosed in U.S. Patent No.
6,257,334, a horizontal injector-producer CSS well is placed offset to a SAGD
well pair at a depth of a production well of the SAGD well pair. The CSS well starts injecting steam into the subterranean reservoir after the SAGD well pair has been in operation for a period described as 3 years and is illustrated as being at a time when the vapor chamber has reached an overburden of the subterranean reservoir. The CSS well continues to inject steam into the subterranean reservoir until fluid communication is established between the CSS well and the SAGD well pair. A similar process was proposed in U.S. Patent No. 7,556,099 with the CSS well being described as starting its process when the vapor chambers from two surrounding SAGD
well pairs have already merged. In the technique of U.S. Patent No. 7,556,099, steam is injected into the subterranean reservoir at a pressure that is high enough for the reservoir matrix of the subterranean reservoir to fracture. When injections from a CSS
well in a SAGD
technique commence after vapor chambers of SAGD well pairs have merged and/or reached the overburden, a vapor chamber formed by steam injections from the CSS well will grow in a primarily vertical direction in order to merge with the vapor chambers already formed by the SAGD process. Such timing of the commencement of injections from the CSS well can still leave an area between the CSS well and the SAGD well pairs in which the heavy oil is not mobilized for recovery of the resources due to the primarily vertical growth of the vapor chamber from the CSS well. Further, steam from the CSS well may be exposed to the overburden of the subterranean reservoir due to the primarily vertical growth of the vapor chamber of the CSS
well, possibly resulting in a portion of the steam energy from the CSS well being lost to rock forming the overburden above the subterranean reservoir.

[0012] Processes to improve horizontal distribution of vapor from wells have been proposed, for example in Canadian Patent Publication No. 2,744,749. The figures of Canadian Patent Publication No. 2,744,749 illustrate a technique in which injection wells in a subterranean reservoir may be horizontally offset as well as vertically offset from production wells. The technique of Canadian Patent Publication No. 2,744,749 is in contrast with a typical SAGD process in which an injection well and a production well are generally horizontally aligned. However, the technique of Canadian Patent Publication No. 2,744,749 is applied to new installations and processes in a subterranean reservoir and not to existing installations and processes.

[0013] Fig. 2 shows a temperature distribution in a subterranean reservoir during a CSS-SAGD technique when injections from the CSS well are commenced after vapor chambers from adjacent SAGD well pairs 204 have merged. The SAGD well pair 204 and the CSS
well 206, through steam injections, each form a vapor chamber which in turn forms an area of increased temperature that is depleted of heavy oil that has already been mobilized, possibly for recovery of the heavy oil. But, an area between the SAGD well pair 204 and the CSS well 206, for which the temperature does not increase, as shown in dark portions 202 in Fig. 2, is an area where heavy oil has not been mobilized for recovery.

[0014] Improving a vapor distribution throughout the subterranean reservoir is desired during thermal recovery processes to mobilize a greater amount of the heavy oil, and thereby recover a greater amount of heavy oil from the subterranean reservoir.
SUMMARY

[0015] The present disclosure provides systems and methods for enhancing oil recovery during thermal recovery processes.

[0016] A method of recovering heavy oil from a subterranean reservoir via a thermal recovery well pair, the thermal recovery well pair comprising an injection well, for injecting injection vapor into the subterranean reservoir to form a vapor chamber, and a production well, at an elevation below the injection well, for recovering heavy oil from the subterranean reservoir, may comprise providing an infill well in an area laterally spaced apart from the thermal recovery well pair. The method may also comprise injecting an injected fluid via the infill well into the subterranean reservoir at a time during which the injected fluid establishes a horizontal planar communication path between the infill well and the vapor chamber. The horizontal planar communication path may enable substantially horizontal planar distribution of the injection vapor within the subterranean reservoir. The method may also comprise producing a produced fluid from the infill well to at least partially recover heavy oil from the horizontal planar communication path. The horizontal planar communication path may provide the horizontal planar communication. The method may also comprise producing heavy oil from at least one of (i) the infill well after the horizontal planar communication has been established and (ii) the production well to recover the heavy oil from the subterranean reservoir.

[0017] A method of recovering heavy oil from a subterranean reservoir may comprise providing two thermal recovery well pairs laterally spaced apart from each other. Each of the two thermal recovery well pairs may comprise an injection well, for injecting injection vapor into the subterranean reservoir, and a production well, at an elevation below the injection well, for removing heavy oil from the subterranean reservoir. The injection vapor may form a vapor chamber above each of the two thermal recovery well pairs. The method may also comprise providing an infill well between and laterally spaced apart from each of the two thermal recovery well pairs. The method may also comprise injecting the injection vapor from each of the injection wells to form the vapor chamber above each of the two thermal recovery well pairs and establishing horizontal planar communication between the infill well and the vapor chambers of the two thermal recovery well pairs by injecting an injected fluid via the infill well into the subterranean reservoir after forming the vapor chambers. The method may also comprise producing the heavy oil from the production wells.

[0018] The foregoing has broadly outlined the features of the present disclosure so that the detailed description that follows may be better understood. Additional features will also be described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

[0019] These and other features, aspects and advantages of the present disclosure will become apparent from the following description and the accompanying drawings, which are described briefly below:

[0020] Fig. 1 is a drawing of a SAGD process used for recovering heavy oil in a subterranean reservoir;

[0021] Fig. 2 is an illustration of a simulated temperature distribution in a CSS-SAGD
process;

[0022] Fig. 3 is a cross section of a SAGD process;

[0023] Fig. 4A is an illustration of a simulated temperature distribution in the subterranean reservoir after horizontal planar communication is established in a horizontal planar heating assisted-SAGD (HPHA-SAGD) process;

[0024] Fig. 4B is an illustration of a simulated temperature distribution in the subterranean reservoir in the HPHA-SAGD process after 856 days;

[0025] Fig. 4C is an illustration of a simulated temperature distribution in the subterranean reservoir in the HPHA-SAGD process after 1000 days;

[0026] Fig. 4D is an illustration of a simulated temperature distribution in the subterranean reservoir in the HPHA-SAGD process after 1300 days;

[0027] Fig. 5 is a plot diagram showing a simulated comparison of a cumulative oil-steam ratio for the HPHA-SAGD process in comparison with SAGD processes;

[0028] Fig. 6 is a plot diagram showing a simulated comparison of oil production rates for the HPHA-SAGD process in comparison with SAGD processes;

[0029] Fig. 7 is a plot diagram showing a simulated comparison of a cumulative oil production for the HPHA-SAGD process in comparison with SAGD processes; and

[0030] Fig. 8 is a possible flow diagram showing the HPHA-SAGD process.

[0031] It should be noted that the figures are merely examples and that no limitations on the scope of the present disclosure are intended hereby. Further, the figures are generally not drawn to scale but are drafted for the purpose of convenience and clarity in illustrating various aspects of the disclosure.

DETAILED DESCRIPTION

[0032] For the purpose of promoting an understanding of the principles of the disclosure, reference will now be made to the features illustrated in the drawings and specific language will be used to describe the same. It will nevertheless be understood that no limitation of the scope of the disclosure is thereby intended. Any alterations and further modifications, and any further applications of the principles of the disclosure as described herein are contemplated as would normally occur to one skilled in the art to which the disclosure relates. It will be apparent to those skilled in the relevant art that some features that are not relevant to the present disclosure may not be shown in the drawings for the sake of clarity

[0033] At the outset, for ease of reference, certain terms used in this disclosure and their meaning as used in this context are set forth below. To the extent a term used herein is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Further, the present processes are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments and terms or processes that serve the same or a similar purpose are considered to be within the scope of the present disclosure.

[0034] A "hydrocarbon" is an organic compound that primarily includes the elements of hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number of other elements may be present in small amounts. Hydrocarbons generally refer to components found in heavy oil or in oil sands. However, the techniques described are not limited to heavy oils but may also be used with any number of other subterranean reservoirs to improve gravity drainage of liquids. Hydrocarbon compounds may be aliphatic or aromatic, and may be straight chained, branched, or partially or fully cyclic.

[0035] "Bitumen" is a naturally occurring heavy oil material. Generally, it is the hydrocarbon component found in oil sands. Bitumen can vary in composition depending upon the degree of loss of more volatile components. It can vary from a very viscous, tar-like, semi-solid material to solid forms. The hydrocarbon types found in bitumen can include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be composed of:
19 weight (wt.) % aliphatics (which can range from 5 wt. % - 30 wt. %, or higher);

19 wt. % asphaltenes (which can range from 5 wt. % - 30 wt. %, or higher);
30 wt. % aromatics (which can range from 15 wt. % - 50 wt. %, or higher);
32 wt. % resins (which can range from 15 wt. % - 50 wt. %, or higher); and some amount of sulfur (which can range in excess of 7 wt. %).
In addition bitumen can contain some water and nitrogen compounds ranging from less than 0.4 wt. % to in excess of 0.7 wt. %. The percentage of the hydrocarbon found in bitumen can vary. The term "heavy oil" includes bitumen as well as lighter materials that may be found in a sand or carbonate reservoir.

[0036] "Heavy oil" includes oils which are classified by the American Petroleum Institute ("API"), as heavy oils, extra heavy oils, or bitumens. The term "heavy oil"
includes bitumen.
Heavy oil may have a viscosity of about 1,000 centipoise (cP) or more, 10,000 cP or more, 100,000 cP or more, or 1,000,000 cP or more. In general, a heavy oil has an API gravity between 22.3 API (density of 920 kilograms per meter cubed (kg/m3) or 0.920 grams per centimeter cubed (g/cm3)) and 10.0 API (density of 1,000 kg/m3 or 1 g/cm3).
An extra heavy oil, in general, has an API gravity of less than 10.0 API (density greater than 1,000 kg/m3 or 1 g/cm3). For example, a source of heavy oil includes oil sand or bituminous sand, which is a combination of clay, sand, water and bitumen. The recovery of heavy oils is based on the viscosity decrease of fluids with increasing temperature or solvent concentration. Once the viscosity is reduced, the mobilization of fluid by steam, hot water flooding, or gravity is possible.
The reduced viscosity makes the drainage quicker and therefore directly contributes to the recovery rate.

[0037] Two locations in a subterranean reservoir are in "fluid communication" when a path for fluid flow exists between the two locations. For example, fluid communication exists between an injection well and a production well when mobilized material can flow down to the production well from the injection well for collection and production.

[0038] A "fluid" includes a gas or a liquid and may include, for example, hot or cold water, a produced or native reservoir hydrocarbon, an injected mobilizing fluid, hot or cold liquid hydrocarbon, solvent, steam, wet steam, gas (e.g., C1, CO2, etc., where C
represents Carbon and 0 represents Oxygen), or a mixture of these, among other materials. "Vapor"
refers to steam, wet steam, mixtures of steam and wet steam, any of which could possibly be used with a solvent and other substances, and any material in the vapor phase.

[0039] "Facility" is a tangible piece of physical equipment through which hydrocarbon fluids are either produced from a subterranean reservoir or injected into a subterranean reservoir, or equipment that can be used to control production or completion operations. In its broadest sense, the term facility is applied to any equipment that may be present along the flow path between a subterranean reservoir and its delivery outlets.
Facilities may comprise production wells, injection wells, well tubulars, wellbore head equipment, gathering lines, manifolds, pumps, compressors, separators, surface flow lines, steam generation plants, processing plants, and delivery outlets. In some instances, the term "surface facility" is used to distinguish those facilities other than wells.

[0040] "Pressure" is the force exerted per unit area by gas on the walls of the volume.
Pressure can be shown as pounds per square inch (psi), kilopascals (kPa), or megapascals (MPa).
"Atmospheric pressure" refers to the local pressure of the air. "Absolute pressure" (psia) refers to the sum of the atmospheric pressure (14.7 psia at standard conditions) plus the gauge pressure. "Gauge pressure" (psig) refers to the pressure measured by a gauge, which indicates only the pressure exceeding the local atmospheric pressure (i.e., a gauge pressure of 0 psig corresponds to an absolute pressure of 14.7 psia). The term "vapor pressure"
has the usual thermodynamic meaning. For a pure component in an enclosed system at a given pressure, the component vapor pressure is essentially equal to the total pressure in the system.

[0041] A "reservoir" or "subterranean reservoir" is a subsurface rock or sand formation from which a production fluid or resource can be harvested. The rock formation may include sand, granite, silica, carbonates, clays, and organic matter, such as bitumen, heavy oil (e.g., bitumen), gas, or coal, among others. Reservoirs can vary in thickness from less than one foot (0.3048 meter (m)) to hundreds of feet (hundreds of meters). The resource is generally a hydrocarbon, such as a heavy oil impregnated sand bed.

[0042] "Thermal recovery processes" include any type of hydrocarbon recovery process that uses a heat source to enhance the recovery, for example, by lowering the viscosity of a hydrocarbon. These processes may use injected mobilizing fluid, such as hot water, wet steam, dry steam, or solvents alone, or in any combination, to lower the viscosity of the hydrocarbon.
Such processes may include subsurface processes, such as thermal steam-based processes, and processes that use surface processing for the recovery, such as sub-surface mining and surface mining. Any of the thermal recovery processes may be used with solvents. For example, thermal recovery processes may include CSS, steam flooding, SAGD, SA-SAGD, thermal enhanced oil recovery, VAPEX, in-situ combustion, and other such processes.

[0043] "Substantial" when used in reference to a quantity or amount of a material, or a specific characteristic of the material, refers to an amount that is sufficient to provide an effect that the material or characteristic was intended to provide. The exact degree of deviation allowable may in some cases depend on the specific context.

[0044] A "wellbore" is a hole in the subsurface made by drilling or inserting a conduit into the subsurface. A wellbore may have a substantially circular cross section or any other cross-section shape, such as an oval, a square, a rectangle, a triangle, or other regular or irregular shapes. The term "well," when referring to an opening in the formation, may be used interchangeably with the term "wellbore." Further, multiple pipes may be inserted into a single wellbore, for example, as a liner configured to allow flow from an outer chamber to an inner chamber.

[0045] The term "base" indicates a lower boundary of resources in a subterranean reservoir that are practically recoverable, by a thermal recovery process using an injected mobilizing fluid, such as steam, solvents, hot water, gas and the like. The base may be considered a lower boundary of a pay zone. The lower boundary may be an impermeable rock layer, including, for example, granite, limestone, sandstone, shale, and the like. The lower boundary may also include layers that, while not completely impermeable, impede the formation of fluid communication between a well on one side and a well on the other side.
Such layers may include inclined heterolithic strata (IHS) of broken shale, mud, silt, and the like.
The resources within the subterranean reservoir may extend below the base, but the resources below the base may possibly not be recoverable, or at least easily recoverable, with gravity assisted techniques.

[0046] "Overburden" refers to the material overlying a subterranean reservoir. The overburden may contain rock, soil, and ecosystem above the subterranean reservoir. During surface mining the overburden is removed prior to the start of mining operations.

[0047] "Permeability" is the capacity of a structure to transmit fluids through the interconnected pore spaces of the structure. The customary unit of measurement for permeability is the milliDarcy (mD).

[0048] "Reservoir matrix" refers to the solid porous material forming the structure of the subterranean reservoir. The subterranean reservoir is composed of the solid reservoir matrix, typically rock or sand, around pore spaces in which resources such as heavy oil may be located.
The porosity and permeability of a subterranean reservoir is defined by the percentage of volume of void space in the rock or sand reservoir matrix that potentially contains resources and water.

[0049] "Fracture" refers to the splitting, breaking, dilating or other displacement of the reservoir matrix of the subterranean reservoir.

[0050] "Fracture pressure" refers to the pressure required to fracture a reservoir matrix of a subterranean reservoir. Different reservoir matrices in different subterranean reservoirs may have different fracture pressures and fracture orientations (i.e., vertical or horizontal) depending upon numerous factors, including but not limited to, geotechnical stresses, induced thermal stresses in thermal processes, pore pressure induced stresses, a timing of pressure alteration in the subterranean reservoir, a composition of the reservoir matrix, a size of the pores of the reservoir matrix, etc.

[0051] "Horizontal planar communication" refers to a fluid communication that is in a primarily horizontal plane direction. There may also be a vertical component to the fluid communication that is smaller than a horizontal component of the fluid communication such that the fluid communication has a substantially horizontal planar distribution.

[0052] "Minimum" and "maximum" when used in conjunction with a discussion of stresses and stress states carry their known and accepted geomechanical definitions. In particular, "minimum" stress generally refers to a state in which a stress in a subterranean reservoir in one direction is at a minimum when compared with the stress in an opposing direction. Similarly, "maximum" stress is also generally defined in relation to stress in an opposing direction.

[0053] In the following description, as an example of a thermal recovery process, reference is made to a SAGD process for recovering heavy oil from a subterranean reservoir.
For better understanding, a brief explanation of a SAGD process is provided below in order to highlight some general techniques of a thermal recovery process.

[0054] Fig. 1 illustrates a SAGD process 100 used for accessing resources in a subterranean reservoir 102. In the SAGD process 100, injection vapor 104, such as steam, solvent and steam-solvent mixtures, can be injected through an injection well 106 into the subterranean reservoir 102. The injection well 106 may be vertically and then horizontally drilled through the subterranean reservoir 102 as shown. A production well 108 may be drilled vertically and then horizontally through the subterranean reservoir 102 such that the production well 108 may lie below the injection well 106 in a SAGD well pair.
Specifically a horizontal section of the production well 108 may lie below a horizontal section of the injection well 106. The injection well 106 and the production well 108 may be drilled from the same pad 110 at a surface 112 or from a different pad at the surface 112. The surface 112 may be a surface of the subterranean reservoir 102. Drilling the injection well 106 and the production well 108 from the same pad may make it easier for the production well 108 to track (i.e., follow a similar path of) the injection well 106. The injection well 106 and the production well 108 may be vertically separated by a suitable distance, such as about 3 to 10 m.
For example, the injection well 106 and the production well 108 may be vertically separated by about 5 m. The injection well 106 and the production well 108 may be vertically separated by the aforementioned amounts in the horizontal and/or vertical sections of the respective injection well 106 and production well 108. Any of the aforementioned ranges may be within a range that includes or is bounded by any of the preceding examples.

[0055] At start-up of the SAGD process, both the injection well 106 and the production well 108 may circulate the injection vapor 104 so that heavy oil between the injection well 106 and the production well 108 is heated enough to flow and be produced through at least one of the injection well 106 and the production well 108. Other start-up techniques may also be used such as liquid solvent injection from the injection well 106 and fluid production from the production well 108. Bull-heading techniques may also be used for start-up in which steam or hot water is injected at pressures, which are higher than normal operating pressures (e.g., normal operating pressures typically being 1.3 to 5MPa) for the SAGD process, through the injection well 106 and fluid is produced from the production well 108.
Further, cyclic steam stimulation may be used in the injection well 106 and in the production well 108. Other methods not mentioned above may also be used for start-up of the SAGD process.

[0056] The injection of the injection vapor 104 via the injection well 106 may result in the mobilization of heavy oil 114 as mobilized heavy oil. The mobilized heavy oil 114 may form a drainage chamber 118 (i.e., within a vapor chamber) having a generally triangular cross section with the production well 108 located at a lower apex 121 of the triangular cross section as the mobilized heavy oil 114 possibly drains to the production well 108. The production well 108 may be switched to a continuous production mode and the injection well 108 may be placed in a continuous injection mode, which involves injecting the injection vapor into the subterranean reservoir 102. The mobilized heavy oil 114 may be removed to the surface 112 via the production well 108 in a mixed fluid stream 116 that may contain heavy oil, condensate and other material, such as water, gases and the like. Sand filters may be used in the production well 108 to decrease sand entrapment of the heavy oil.

[0057] The injection well 106 may comprise injection wells. The production well 108 may comprise production wells. If the production well 108 comprises production wells, the mixed stream 116 from the production wells may be combined and then sent to a processing facility 120. If the production well 108 comprises a single well, the mixed stream 116 from the production well 108 may be sent to the processing facility 120. At the processing facility 120, the mixed stream 116 may be separated. The heavy oil 114 in the mixed stream may be sent on for further refining 122. The water in the mixed stream 116 may be recycled to a vapor generation unit within the processing facility 120 and used to generate the injection vapor 104 used for the SAGD process 100.

[0058] Although the injection well 106 may receive the injection vapor 104, the production well 108 may also receive the injection vapor 104 or the production well 108 may receive the injection vapor 104 instead of the injection well 106.

[0059] In a subterranean reservoir containing heavy oil, a thermal recovery process, such as a SAGD process, of the above kind, can be carried out to reduce a viscosity of the heavy oil enabling production of the heavy oil. Within such a subterranean reservoir, one or more thermal recovery well pairs may be placed for the production of the heavy oil.
A vapor chamber having a generally triangular cross section forms above each thermal recovery well pair due to the injection vapor injected via the injection well of the thermal recovery well pair.
The injection vapor reduces the viscosity of the heavy oil for mobilization and possibly production of the heavy oil. The vapor chamber forms an area from which the heavy oil may be mobilized and eventually possibly drained and depleted during the thermal recovery process.

[0060] Total heavy oil recovery from the thermal recovery process is affected by a distribution of injection vapor in the subterranean reservoir and fluid communication within the subterranean reservoir, both of which affect a temperature distribution in the subterranean reservoir. Given that the vapor chambers have a generally triangular cross section, injection vapor is distributed in the subterranean reservoir within the generally triangular shape of the vapor chambers. This generally triangular cross section may exacerbate uneven distribution of injection vapor within the subterranean reservoir when thermal recovery well pairs are placed nearly parallel to each other in the subterranean reservoir. Portions of the subterranean reservoir that fall between the generally triangular cross section of the vapor chambers may not receive a temperature increase from the injection vapor, which may result in heavy oil in the portions of the subterranean reservoir that are outside of the vapor chambers not being heated by the injection vapor. The lack of heating may result in heavy oil between thermal recovery well pairs that may remain unmobilized and thus not recovered after recovery operations in the subterranean reservoir have finished.

[0061] The present disclosure may include methods of recovering heavy oil from a subterranean reservoir.

[0062] The thermal recovery well pair may be shown by way of example in Fig. 3 which illustrates an example cross section of multiple thermal recovery well pairs 304, 306. While Fig.
3 shows two thermal recovery well pairs 304, 306 as an example, there may be only a single thermal recovery well pair 304, 306 or there may be more than two thermal recovery well pairs 304, 306. The general discussion below will use the example of one thermal recovery well pair 304, 306. Further discussion of other examples will follow.

[0063] The thermal recovery well pair 304, 306 may be any suitable well pair in a thermal recovery process. The thermal recovery well pair 304, 306 may include an injection well 314, 316 and a production well 324, 326. The injection well 314, 316 may receive injection vapor.
The injection well 314, 316 may therefore be for injecting the injection vapor into a subterranean reservoir 302. The injection vapor may be steam, solvent or a steam-solvent mixture. The injection vapor injected into the subterranean reservoir 302 may form a vapor chamber 334, 336. The production well 324, 326 may receive heavy oil from the subterranean reservoir 302. The production well 324, 326 may therefore be for recovering heavy oil from the subterranean reservoir 302. The production well 324, 326 may be at an elevation below the injection well 314, 316. Specifically, a horizontal portion of the production well 324, 326 may be at an elevation below a horizontal portion of the injection well 314, 316.
The injection well 314, 316 may include the horizontal portion of the injection well 314, 316 (i.e., horizontal injection well portion) and a vertical portion of the injection well 314, 316 (i.e., vertical injection well portion). Similarly, the production well 324, 326 may include the horizontal portion of the production well 324, 326 (i.e., horizontal production well portion) and a vertical portion of the production well 324, 326 (i.e., vertical production well portion). The horizontal injection well portion may extend from the vertical injection well portion. The horizontal production well portion may extend from the vertical production well portion.

[0064] The method of recovering heavy oil may comprise providing an infill well in an area laterally spaced apart from the thermal recovery well pair.

[0065] The infill well may be shown by way of example in Fig. 3 which illustrates an example cross section of an infill well 310. While Fig. 3 shows a single infill well 310 as an . .
example, there may be more than one infill well 310. The general discussion below will use the example of one infill well 310. Further discussion of other examples will follow.

[0066] The infill well 310 may be, for example, a well in a CSS
process. The infill well 310 may be placed in an area of the subterranean reservoir 302 containing heavy oil that has not or is not being mobilized by the thermal recovery process. The infill well 310 may be placed in this area to establish horizontal planar communication in the area thereby assisting in the mobilization and production of heavy oil from this area. A horizontal portion of the infill well 310 may be positioned at the same elevation, lower than, higher than or at variable elevation compared to the horizontal portion of the production well 324, 326. While Fig.
3 illustrates the horizontal portion of the infill well 310 being positioned at or below the elevation of the horizontal portion of the production well 324, 326, this relative position may change according to the position of the thermal recovery well pair 304, 306 within the subterranean reservoir 302 and/or the geological features of the subterranean reservoir 302.

[0067] The method of recovering heavy oil may comprise injecting injected fluid via the infill well 310 into the subterranean reservoir 302. The injected fluid may be a gas or a liquid and may include, for example, hot or cold water, a produced or native reservoir hydrocarbon, an injected mobilizing fluid, hot or cold liquid hydrocarbon, solvent, steam, wet steam, gas (e.g., C1, CO2, etc., where C represents Carbon and 0 represents Oxygen), or a mixture of these, among other materials.

[0068] The injected fluid may be injected at a time during which the injected fluid establishes a horizontal planar communication path between the infill well 310 and the vapor chamber 334, 336 of the thermal recovery well pair 304, 306. The initiation of the infill well's injections of the injected fluid can be based on a start time of the thermal recovery well pair 304, 306 operations or according to a progress of the thermal recovery well pair 304, 306 operations. The initiation can be affected by the individual properties of the subterranean reservoir 302. The primary objective of the injections of the injected fluid from the infill well 310 is to create a horizontal planar communication, which is a type of fluid communication, between the infill well 310 and the vapor chamber 334, 336.

[0069] The infill well 310 injects the injected fluid into the subterranean reservoir 302 early in the thermal recovery process at a time when such horizontal planar communication can be used to distribute injection vapor injected from the injection well 314, 316 in a generally horizontal plane and improve heat distribution within the subterranean reservoir 302. "Early"
in the thermal recovery process may be at any time when the establishment of horizontal planar communication can distribute the injection vapor in a substantially horizontal plane. The time during which the injected fluid is injected from the infill well 310 may be any suitable time during which the injected fluid establishes the horizontal planar communication path between the infill well 310 and the vapor chamber 334, 336 of the thermal recovery well pair 304, 306.
For example, the time may be upon formation of the vapor chamber 334, 336, prior to multiple vapor chambers 334, 336 merging, prior to the vapor chamber 334, 336 reaching an overburden of the subterranean reservoir 302, no later than when a height of the vapor chamber 334, 336 is no more than 5% of a height of the subterranean reservoir 302 above the thermal recovery well pair 304, 306, or after the injection vapor causes a primarily minimum vertical stress state in a reservoir matrix of the subterranean reservoir 302.
A primarily minimum vertical stress state in the subterranean reservoir 302 will be discussed in greater detail below.

[0070] When vapor chambers 334, 336 of multiple thermal recovery well pairs 304, 306 have merged, the likelihood of creating a horizontal planar communication is reduced and a probability of creating a vertical fluid communication between the infill well 310 and the merged vapor chamber 334, 336 is increased. The increased probability of creating a vertical fluid communication after the vapor chambers 334, 336 have merged is due to a vapor chamber created by the infill well 310 growing in a primarily vertical direction in order to merge with the merged vapor chambers 334, 336, which is promoted by temperature distribution in the subterranean reservoir 302 caused by the injection vapor from the injection well 314, 316.
Distributing the injection vapor in a primarily vertical plane does not improve heat distribution and hydrocarbon recovery as effectively as a process taking advantage of horizontal planar communication. By injecting the injected fluid via the infill well 310 at a time that is early in the thermal recovery process, the resulting fluid communications are primarily horizontal planar fluid communications and not primarily vertical fluid communications.
Injecting the injected fluid early in the thermal recovery process results in a vapor chamber from the infill well 310 that is not encouraged to grow in the vertical direction in order to merge with the merged vapor chambers 334, 336. Further, injecting the injected fluid at high pressures from the infill well 310 and/or by having the subterranean reservoir 302 in a state favoring maximum horizontal stress, the resulting fluid communications are primarily horizontal planar fluid communications and not primarily vertical fluid communications.

[0071] The infill well 310 may inject injected fluid into the subterranean reservoir 302 at a pressure that may be greater than a fracture pressure of the surrounding reservoir matrix of the subterranean reservoir 302. The pressure may be sufficient to cause fracture or dilation of the reservoir matrix of the subterranean reservoir 302 in the area between the infill well 310 and the thermal recovery well pair 304, 306. Injection of the injected fluid at such a pressure may cause the reservoir matrix of the subterranean reservoir 302 to fracture or dilate. As a result of an appropriate timing of the injections of the injected fluid from the infill well 310, a stress distribution in the reservoir matrix between the infill well 310 and the thermal recovery well pair 304, 306 can be at a minimum vertical stress state and a maximum (or primarily) horizontal stress state. Injections of the injected fluid from the infill well 310 at such a time may cause horizontal fractures in the reservoir matrix of the subterranean reservoir 302, which provide the horizontal planar communication path and result in the horizontal planar communication.

[0072] The fracture pressure and orientation (i.e., vertical, horizontal, or a mixture of both) in the subterranean reservoir 302 is dependent upon geomechanical stresses in the reservoir matrix. The geomechanical stress can be due to a natural geotechnical state of stresses in the reservoir matrix. The geomechanical stress could be induced due to pore pressure induced stresses or by temperature changes, which will be thermal induced stress.
The initial geomechanical stress state (e.g., pore, geotechnical, etc.) in a shallow heavy oil subterranean reservoir matrix generally has minimum vertical effective stress favoring a horizontal fracture if fluid is injected at or above fracture pressure. For example, in the Athabasca oil sand region that has relatively low depths (e.g., less than 400 meters), the weight of the overburden released due to the melting of an ancient glacier results in natural geotechnical stresses that are mainly at a minimum vertical stress state. If the reservoir pressure is increased above the weight of the overburden, the subterranean reservoir may part in a horizontal planar manner causing the overburden to lift. Induced thermal and pore pressure stresses can convert a subterranean reservoir that is in a minimum horizontal stress state to a minimum vertical stress state due to lateral expansion of the reservoir matrix and increasing the horizontal stresses.

[0073] In shallow subterranean reservoirs with a minimum effective vertical stress state, by starting injected fluid injections from the infill well 310 relatively early, a horizontal fracture and therefore a horizontal planar communication between the thermal recovery well pair 304, 306 can be established. In cases where the subterranean reservoir is deeper (e.g., possibly having a larger or heavy overburden) or has an initial maximum vertical stress state, the stress state may favor a vertical fracture. However, due to a temperature increase in the subterranean reservoir caused by the thermal recovery process through injections from the thermal recovery well pair 304, 306 and the infill well 310, thermally induced stresses may shift a geomechanical stress state of such a subterranean reservoir in a region between the thermal recovery well pair 304, 306 to a minimum vertical stress state, enabling horizontal fractures between the infill well 310 and the thermal recovery well pair 304, 306 to produce horizontal planar communication.

[0074] Commencement of injections from the infill well 310 can be determined, for example, by using a geomechanical simulation of the reservoir matrix to determine the best time for starting fluid injections based on properties of the subterranean reservoir 302. A
geologic model of the subterranean reservoir may be created and may include, for example, open hole log data, cased hole log data, core data, recovery process well trajectories, 2-dimensional (2D) seismic data, 3-dimensional (3D) seismic data, or other remote surveying data, or any combination of these. For example, prior to the start of the thermal recovery process, a geologic model can be created for the development area. Available open hole, cased hole log, 2D and 3D seismic data, and knowledge of the depositional environment setting can all be used in the construction of this model. The information generated by the model may . .
then be used in a reservoir simulation model to provide predictions of fluid flow, reservoir geometry, and the like. The geologic model, reservoir model and knowledge of surface access constraints can then be used to complete the layout of the infill well(s) and/or the thermal recovery well pair(s). After the infill well(s) and/or the thermal recovery well pair(s) have been drilled, data collected during their drilling in addition to data collected during the operation of the thermal recovery process, such as cased hole logs including temperature logs, observation wells, additional time lapse seismic or other remote surveying data, can be used to update the geologic model, which may be used to predict the evolution of the depletion patterns as the recovery process matures. The depletion patterns within the subterranean reservoir may be influenced by well placement decisions, geological heterogeneity, well failures, and day to day operating decisions.

[0075] The infill well 310 may start injecting the injected fluid after a small vapor chamber 334, 336 has formed above the thermal recovery well pair 304, 306. Such a "small" vapor chamber 334, 336 can be, for example, a height of no more than 5% of the height of the subterranean reservoir 302 above the thermal recovery well pair 304, 306, or any height within this range. An actual height of the vapor chamber 334, 336 at the time that infill well operations start may be determined on an individual basis according to the factors outlined above.

[0076] The horizontal planar communication path may enable substantially horizontal planar distribution of the injection vapor from the injection well 314, 316.
Typically there is an emphasis on growth and expansion of the vapor chamber 334, 336 of the thermal recovery well pair 304, 306 in a vertical direction. As the injection vapor is injected into the subterranean reservoir 302, the vapor chamber 334, 336 grows vertically until the vapor chamber 334, 336 eventually reaches the overburden of the subterranean reservoir 302. Injecting injected fluid into an area between thermal recovery well pairs 304, 306 or beside a thermal recovery well pair 304, 306 during an early stage of a thermal recovery process (e.g., prior to the vapor chambers of different thermal recovery well pairs 304, 306 merging or reaching the overburden of the subterranean reservoir 302) promotes fluid communication in a substantially horizontal direction, which may create the horizontal planar communication path. The injection vapor from the injection wells 314, 316 may travel along the horizontal planar communication path between the thermal recovery well pair 304, 306 and the infill well 310. The horizontal planar communication path may enable the injection vapor from the injection well 314, 316 to traverse through the subterranean reservoir 302 in a generally horizontal direction. Such horizontal traversal of the injection vapor provides improved fluid communication between the thermal recovery well pair 304, 306 and the infill well 310 and promotes mobilization of heavy oil in an area between the thermal recovery well pair 304, 306 and outside the vapor chamber 334, 336.

[0077] Early establishment of the horizontal planar communication path enabling the injection vapor to travel in a somewhat horizontal manner and provide heating in an area of the subterranean reservoir 302 along the horizontal planar communication path helps improve performance of the thermal recovery process as well as improves heavy oil production rates early in the life span (e.g., prior to 1500 days) of the thermal recovery process. Fig. 6 shows performance and improvement of heavy oil production rates with an early establishment of the horizontal planar communication where SAGD is the thermal recovery process.
When SAGD is used as the thermal recovery process, the process of establishing horizontal planar communications in the manner set out above may be called horizontal planar heating assisted SAGD (HPHA-SAGD).

[0078] The horizontal planar communication path may provide the horizontal planar communication. The horizontal planar communication may allow for the substantially horizontal planar distribution of the injection vapor.

[0079] The method of recovering heavy oil may comprise producing produced fluids from the infill well 310 to at least partially recover heavy oil from the horizontal planar communication path. The produced fluids may include the injected fluid that is injected via the infill well 310, heavy oil, and other fluids from within the subterranean reservoir 302, such as, for example, water. The heavy oil may flow to the infill well 310 by natural conditions or as a result of some temperature increase from a thermal recovery process occurring as a result of the thermal recovery well pair or due to mobilization from the injected fluid (e.g., reduced viscosity from a solvent if the injected fluid includes a solvent, or reduced viscosity from . .
increased temperature if the injected fluid is a heated fluid, or increased pressure from injection of the injected fluid at a pressure higher than that currently in the subterranean reservoir 302, etc.). The produced fluids may be the result of the injected fluid moving through the reservoir matrix to create the horizontal planar communication path. That is, the produced fluid may include components, such as heavy oil, that are in the horizontal planar communication path and are to be removed from the horizontal planar communication path.
The produced fluids may also be components, such as water or heavy oil that has an already reduced viscosity, that would drain under gravity to the infill well 310.

[0080] The infill well 310 may be in an area laterally spaced apart from the thermal recovery well pair 304, 306. The infill well 310 may be substantially parallel to or angular to the thermal recovery well pair 304, 306. The relative configuration of the thermal recovery well pair 304, 306 and the infill well 310 may be based on geological configurations and properties of the subterranean reservoir 302. The infill well 310 may be placed within the subterranean reservoir 302, and spaced appropriately from the thermal recovery well pair 304, 306, to enable the establishment of horizontal planar communication with the vapor chamber 334, 336 of the thermal recovery well pair 304, 306. The infill well 310 may be placed in an area of the subterranean reservoir 302 containing heavy oil that has not or is not being mobilized by the thermal recovery process.

[0081] The thermal recovery well pair 304, 306 may comprise two thermal recovery well pairs 304, 306 or more than two thermal recovery well pairs 304, 306. If the thermal recovery well pair 304, 306 comprises two thermal recovery well pairs 304, 306, the infill well 310 may be between the two thermal recovery well pairs 304, 306 and laterally spaced apart from each of the two thermal recovery well pairs 304, 306. If the thermal recovery well pair 304, 306 comprises more than two thermal recovery well pairs304, 306, the infill well 310 may comprise infill wells 310. One of the infill wells 310 may be between two or more than two thermal recovery well pairs 304, 306 and be laterally spaced apart from each of the two or more than two thermal recovery well pairs304, 306.

[0082] There may be multiple infill wells 310 that may be generally parallel to or angular to one or more thermal recovery well pairs 304, 306 and/or with respect to other infill well(s) 310. The relative configuration of the thermal recovery well pairs 304, 306 and the infill well(s) 310 can be determined based on configurations of possible existing thermal recovery well pairs 304, 306 and the geological configuration and properties of the subterranean reservoir 302.
For example, if there is a large lateral spacing between the thermal recovery well pairs 304, 306 (e.g., greater than 150 meters depending on the properties of the subterranean reservoir 302), then there may be multiple infill wells 310 spaced between each thermal recovery well pair 304, 306 to create horizontal planar communication between the thermal recovery well pairs 304, 306. Closer lateral spacing of the thermal recovery well pairs 304, 306 and the infill well(s) 310 contributes to quicker establishment of horizontal planar communications but may add to a cost of recovering the heavy oil. In general, the infill wells may be in a generally alternating configuration with the thermal recovery well pairs with at least one infill well possibly being provided in between adjacent thermal recovery well pairs.

[0083] The method of recovering heavy oil may comprise producing heavy oil from at least one of (i) the infill well after the horizontal planar communication has been established and (ii) the production well to recover the heavy oil from the subterranean reservoir. The heavy oil may flow down to the production well due to a reduction in viscosity as previously described and be produced from the production well or the infill well.

[0084] The infill well 310 may be an injector-producer well in that the infill well 310 can act as an injection well by injecting the injected fluid into the subterranean reservoir 302 as well as act as a production well by producing the produced fluids or heavy oil from the subterranean reservoir 302. After the horizontal planar communications have been established, the infill well 310 may operate in a production mode producing heavy oil from the subterranean reservoir 202.

[0085] The method of recovering heavy oil may comprise repeatedly injecting the injected fluid and producing the produced fluid. The infill well 310 may alternate between operating as an injection well and as a production well.

[0086] The infill well 310 may inject a mobilizing fluid into the subterranean reservoir 302 and then inject an infill well vapor into the subterranean reservoir 302. The mobilizing fluid may be cold water, hot water, cold liquid hydrocarbon solvent, hot liquid hydrocarbon solvent, , steam, wet steam, gas and a mixture of at least two of cold water, hot water, cold liquid hydrocarbon solvent, hot liquid hydrocarbon solvent, steam, wet steam and gas.
The infill well vapor may be steam, solvent and steam-solvent mixture. The infill well 310 may repeatedly inject the infill well vapor and produce the produced fluids.

[0087] The infill well 310 generally initiates its operations by performing a first fluid injection cycle. The first fluid injection cycle injects the injected fluid into the subterranean reservoir 302 to establish horizontal planar communication between the thermal recovery well pair 304, 306 and the infill well 310. The injected fluid during this first fluid injection cycle can be, for example, hot or cold water, gas (such as C1, CO2, etc.), steam, wet steam, cold or hot liquid hydrocarbon solvent or any mixture of these or any other similar suitable fluid. The injected fluid is injected from the infill well 310 until either an injection pressure drops or a high pressure is observed at the thermal recovery well pair 304, 306, which may indicate that horizontal planar communication has been established at least between the thermal recovery well pair 304, 306 and the infill well 310.

[0088] The properties of the subterranean reservoir 302 and the heavy oil may be such that the heavy oil begins to drain down towards the infill well 310 as soon as the infill well 310 has been drilled. In such a case, the infill well 310 may operate as a production well prior to performing the first fluid injection cycle to remove the heavy oil that has already been mobilized.

[0089] Depending upon the injected fluid used for the first fluid injection cycle, the infill well 310 may switch to a production cycle after being used in an injection cycle. If the injected fluid from the first fluid injection cycle is a vapor that has mobilized the heavy oil above the infill well 310 then the production cycle may commence immediately after the first fluid injection cycle and may continue for either a specified period of time or until no more produced fluid is produced. If the injected fluid in the first fluid injection cycle is a mobilizing fluid other than vapor (e.g., hot or cold water, gas, hot or cold liquid hydrocarbon solvent, etc.) then the first fluid injection cycle may be followed by a vapor injection cycle injecting an infill well vapor to heat the heavy oil along the horizontal planar communication path established after injection of the mobilizing fluid. The infill well vapor may be, for example, steam, solvent, and steam-solvent mixtures. Such subsequent injections of the infill well vapor may continue until, for example, the injection pressure drops (e.g. to below an initial injection pressure) or until high pressure is observed at the thermal recovery well pair 304, 306. The first few cycles of injections of the injected fluid, the mobilizing fluid and/or the infill well vapor create a horizontal planar communication path within the reservoir matrix of the subterranean reservoir 302 and mobilize heavy oil along that horizontal planar communication path for possible removal by the infill well 310 during the production cycle with the produced fluids. If the injected fluid injected during the first fluid injection cycle is the mobilizing fluid but does mobilize the heavy oil for production, then injection of the infill well vapor may not be performed prior to the production cycle.

[0090] The operation of the infill well 310 alternating between injection of vapor and/or fluids and production of produced fluids may continue until horizontal planar communication between the thermal recovery well pair 304, 306 and the infill well 310 is established. This operation may continue until after this horizontal planar communication is established. This operation may continue through the life of the thermal recovery process in the subterranean reservoir 302.

[0091] There may be multiple cycles of injection and production by the infill well 310 that are performed until the horizontal planar communication is established and can be sustained and the cold heavy oil does not plug the horizontal planar communication paths. Even if horizontal planar communication between the thermal recovery well pair 304, 306 and the infill well 310 is established after the first injection cycle of the infill well 310, the horizontal planar communication paths may be blocked by viscous heavy oil not removed during the production cycle or that may have flowed into the horizontal planar communication paths from cold parts of the subterranean reservoir 302 that are above the horizontal planar communication paths.
After the horizontal planar communication paths have been established, the infill well 310 may operate primarily as a production well. At this point, injection vapor from the vapor chamber 334, 336 may flow into the horizontal planar communication paths and heat up the heavy oil above the horizontal planar communication paths, which will mobilize and drain down into the production well 324, 326 and the infill well 310. However, the infill well 310 may also continue to have injection cycles to inject the infill well vapor as necessary to maintain the horizontal planar communication paths and mobilize viscous heavy oil in the horizontal planar communication paths at predetermined times or at requested times if there is a blockage in the horizontal planar communication.

[0092] The injected fluid may be cyclically injected from the infill well 310 and the produced fluid may be produced to create solvent fingers. In subterranean reservoirs where the stress state may not favor horizontal fractures, solvent fingering may offer an alternate mechanism for generating horizontal planar communication. Solvent fingering is a mechanism whereby the injected fluid invades a subterranean reservoir that is saturated with the heavy oil, and occurs when solvent is injected into heavy oil. The injected fluid is less viscous than the heavy oil in the subterranean reservoir. Solvent fingers will propagate towards regions of lower pressure. The horizontal planar communication can be generated by cyclic injection and production of solvent from the infill well 310 to establish a finger network of high mobility. The solvent fingers form, at least in part, path(s) of the horizontal planar communication.

[0093] The infill well 310 may operate to inject the injected fluid and produce the produced fluid using known processes to establish horizontal planar communication in combination with the above mentioned timing of the commencement of operations from the infill well 310. For example, the infill well 310 may operate using at least one of cyclic steam stimulation, and cycle solvent stimulation.

[0094] The infill well 310 may be completed with flow control devices configured to evenly distribute the injected fluid. For example, the infill well 310 may comprise a flow control devide of a limited entry perforation (LEP) type in which the infill well 310 has only a limited number of perforations for injection of the injected fluid. A sufficient fluid injection rate from the infill well 310 is used to restrict capacity of the perforations so as to increase uniformity of injection rate across the entire infill well 310. The increased uniform injection rate enhances uniform vaporing and fracturing in the subterranean reservoir 302. The total area of perforations may be selected to limit the influx of vapor during continuous production. The infill well 310 may use an inflow-outflow control device (ICD-OCD) to improve the uniform fluid . .
injection and production along the infill well 310. This enhances uniform vapor injection conformance and fracturing the subterranean reservoir.

[0095] In a case where the infill well 310 and the thermal recovery well pairs 304, 306 are not parallel, fracture or communication may be formed in a part of the subterranean reservoir 302 where the infill well 310 has a closer lateral spacing to a production wells 324, 326 and not formed in an area further away from the production wells 324, 326. The use of an inflow-outflow control device (ICD-OCD) on the infill well 310 and an inflow control device on the production wells 324, 326 may be employed to overcome concerns and improve uniform injected fluid injection distribution and conformance along the infill well 310.

[0096] The method of recovering heavy oil may comprise providing two thermal recovery well pairs in a subterranean reservoir. The two thermal recovery well pairs may be any suitable well pair from a thermal recovery process. The two thermal recovery well pairs may be laterally spaced apart from each other. Each of the two thermal recovery well pairs may include an injection well and a production well. Each of the injection wells may be configured as previously described with each of the injection wells injecting injection vapor to form a vapor chamber above each of the thermal recovery well pairs. The injection vapor may comprise the injection vapor as previously described. Each of the production wells may be configured as previously described.

[0097] The method of recovering heavy oil may comprise providing an infill well in the subterranean reservoir. The infill well may be positioned and/or configured like the infill well previously described.

[0098] The method of recovering heavy oil may comprise injecting the injection vapor from each of the injection wells into the subterranean reservoir. The injection vapor may form the vapor chambers above each of the two thermal recovery well pairs when the injection vapor is injected into the subterranean reservoir.

[0099] The method of recovering heavy oil may comprise establishing horizontal planar communications between the infill well and the vapor chambers of the two thermal recovery well pairs. The horizontal planar communications may be established by injecting the injected fluid via the infill well into the subterranean reservoir after formation of the vapor chambers.

The injected fluid may comprise the injected fluid as previously described.
The injected fluid may be injected at a time and under conditions and pressures previously described.

[00100] The method of recovering heavy oil may comprise producing fluids from each of the production wells to recover the heavy oil. Details of the production fluid may be the same as those previously described in this application. The heavy oil may flow to the infill well in the same manner as previously described.

[00101] The infill well may operate in an injection mode or in a production mode as previously described. Establishing the horizontal planar communication may comprise alternating operating the infill well between an injection mode to inject the injected fluid and a production mode to produce the produced fluid from the infill well until the horizontal planar communication is established.

[00102] The method of recovering heavy oil may comprise operating the infill well in a production mode to produce a produced fluid after establishing the horizontal planar communication.

[00103] The method of recovering heavy oil may comprise operating the infill well in one of a production mode to produce the produced fluid and an injection mode to inject the injected fluid after establishing the horizontal planar communication. The infill well may operate in the injection mode at predetermined intervals to ensure that the horizontal planar communication remains established as previously described. The infill well may operate in the injection mode at requested times when there is a blockage in the horizontal planar communication as previously described.

[00104] The infill well 310 may inject a mobilizing fluid into the subterranean reservoir 302, inject an infill well vapor into the subterranean reservoir 302 and then produce the produced fluid. The mobilizing fluid may be the mobilizing fluid as previously described. The infill well vapor may be the infill well vapor as previously described. The infill well 310 may repeatedly inject the infill well vapor and produce the produced fluids until the horizontal planar communication is established.

[00105] Establishing the horizontal planar communication may be performed by any thermal recovery process.

[00106] The horizontal planar communication path may enable the injection vapor from the injection wells 314, 316 to travel along the horizontal planar communication paths forming the horizontal planar communication between the thermal recovery well pairs 304,306 and the infill well 310. By providing such horizontal planar communication paths, the distribution of the injection vapor between the thermal recovery well pairs 304, 306 is improved.
With an improved injection vapor distribution, a heat distribution and mobilization of the heavy oil within the subterranean reservoir 302 improves and contact of the injection vapor or injected fluid with the overburden is reduced, which in turn reduces heat loss to the overburden and improves the oil-to-steam ratio of the thermal recovery process, which is illustrated in Fig. 5 with SAGD as the specific thermal recovery process.

[00107] Some subterranean reservoirs have a high mobility water saturated sand zone located at or near the bottom of a pay zone containing the heavy oil. This high mobility zone may be used for sub-fracture fluid injections to establish horizontal planar communication. For example, the infill well 310 may be placed within this high mobility zone and fluid or vapor may be injected from the infill well 310 into this high mobility zone to establish horizontal planar communication.

[00108] Fig. 4A-4D illustrates simulated temperature distributions in the subterranean reservoir after the horizontal planar communication between the infill well 310 and the thermal recovery well pair 304, 306 has been attained at various time points. Figs. 4A-4D illustrate the use of SAGD as the exemplary thermal recovery process. The darkest areas 402 in Figs. 4A-4D
show areas in the subterranean reservoir containing immobilized, unrecovered heavy oil while the middle grey areas 404 illustrate a depleted zone in which the heavy oil has been mobilized and recovered. The lighter transition areas 406 between the dark areas 402 and the middle grey areas 404 in Figs. 4A-4D show areas in the subterranean reservoir in which the heavy oil has been heated for mobilization and recovery of these heavy oil has commenced. Fig. 4A
illustrates the temperature distribution in the subterranean reservoir after horizontal planar communication between an infill well 408 and a SAGD well pair 410 has been established (at approximately 538 days, which is considered to be relatively early in the life of SAGD
operations). The temperature distribution shown in Fig. 4A is for the infill well 408 that started . .
injecting the injected fluid to establish horizontal planar communication with the SAGD well pair 410 shortly after the vapor chamber of the SAGD well pair 410 was established according to the discussions above (e.g., approximately 500 days). Fig. 48 illustrates a simulated temperature distribution in the subterranean reservoir with the infill well 408 and the SAGD
well pair 410 (e.g., at approximately 800 days). Fig. 48 illustrates a temperature distribution in the subterranean reservoir after approximately 3-4 cycles of injection/production from the infill well 408 with the third and fourth cycles opening horizontal planar communication paths again that were established in the first and second injection/production cycles.
Fig. 4C illustrates a simulated temperature distribution in the subterranean reservoir with the infill well 408 and the SAGD well pair 410 after 1000 days. Fig. 4D illustrates a simulated temperature distribution in the subterranean reservoir with the infill well 408 and the SAGD well pair 410 after approximately 1300 days.

[00109] As can be seen from Figs. 4A-4D, in comparison with Fig. 2, timing the injected fluid injections from the infill well to just after formation of the SAGD
vapor chambers and establishing a horizontal planar communication results in improved heat distribution and vertical growth of a horizontal planar vapor chamber formed from merging of the vapor chambers of the SAGD well pairs and a vapor chamber of the infill well. This improved performance is in comparison with injecting the injected fluid to attempt to establish fluid communication with the SAGD vapor chamber after the SAGD vapor chambers have formed and merged (state shown at 1470 days in Fig. 2). In this case, the infill well 206 tends to form a vapor chamber having a generally triangular cross section similar to the SAGD
vapor chambers and not a vapor chamber having an increased horizontal planar distribution with a heat distribution in the subterranean reservoir between the infill well 206 and the SAGD well pairs 204 that is not as effective as the horizontal planar vapor chamber in heating cold unrecovered heavy oil in the subterranean reservoir and minimizing vapor exposure to the overburden to reduce heat loss.

[00110] Fig. 5 illustrates simulated cumulative oil-steam ratios for traditional SAGD
operations, CSS-SAGD operations and horizontal planar heating assisted SAGD
(HPHA-SAGD) operations (presently described process). Fig. 6 illustrates simulated oil production rates for traditional SAGD operations, CSS-SAGD operations and HPHA-SAGD operations (presently described process). Fig. 7 illustrates simulated cumulative oil production for traditional SAGD
operations, CSS-SAGD operations and HPHA-SAGD operations (presently described process). As can be seen in Figs. 5-7, the process described herein provides improved cumulative oil-steam ratios sooner than SAGD and CSS-SAGD operations as well as higher oil rates and cumulative oil production sooner than the compared other processes.

[00111] Fig. 8 is a drawing illustrating an exemplary flow diagram of a method 800.
Thermal recovery well pairs, each comprising an injection well and a production well, are provided in step 802 and operated in step 804. The infill well is provided in step 806. The thermal recovery process in the subterranean reservoir may have already commenced when the infill well is drilled, although the infill well may be provided prior to such commencement (e.g., prior to step 804). A timing of the start of injected fluid injections by the infill well into the subterranean reservoir is determined in step 808. The infill well may start injections when the injected fluid injected from the infill well into the subterranean reservoir can establish horizontal planar communication paths that may enable the horizontal planar communications.
Such a time may also be prior to the merging of the vapor chambers of different thermal recovery well pairs. Such a time may also be when injection vapor injected from one of the injection wells has caused a primarily vertical stress state in a reservoir matrix of the subterranean reservoir. The infill well injects the injected fluid into the subterranean reservoir at the determined time in step 810. Thereafter, the infill well may perform cyclic operations, alternating between injecting the injected fluid into the subterranean reservoir and recovering produced fluids therefrom as a production well in step 812 until horizontal planar communication between the thermal recovery well pair vapor chambers is established. The recovered produced fluids may include heavy oil along with some of the injected fluids. With the infill well injecting the injected fluid into the subterranean reservoir, the infill well forms an infill well horizontal planar vapor chamber in a depleted zone. Once the infill well and the thermal recovery well pair vapor chambers are in fluid communication, as determined in step 814, the infill well may operate in a production well mode in step 816. An infill well production mode condition is assessed in step 818. The infill well production mode condition may be based on whether the horizontal planar communication is still active, the infill well is still producing heavy oil or a predetermined period of time has passed since the horizontal planar communications have been established. For example, the infill well production mode condition may be satisfied if the horizontal planar communication is still active, or if the infill well is still producing heavy oil, or if a time is within a predetermined period of time after the horizontal planar communication has been established and within the predetermined period of time the production mode for the infill well is to continue. If the infill well production mode condition is satisfied then the infill well may continue in the production mode. If the infill well production mode condition is not satisfied the infill well may temporarily operate in an injection mode in step 820 before checking the infill well production condition again and possibly returning to the production mode.

[00112] While the above have discussed the use of infill well(s) to establish horizontal planar communication in the presence of a thermal recovery process in which a SAGD process is specifically described, the above techniques can be used with other processed, such as, for example, VAPEX (vapor extraction process), cyclic steam stimulation, steam flooding, solvent assisted SAGD, thermal enhanced oil recovery, in-situ combustion, etc.

[00113] As utilized herein, the terms "approximately," "about," and similar terms are intended to have a broad meaning in harmony with the common and accepted usage by those or ordinary skill in the art to which the subject matter of this disclosure pertains. It should be understood by those of skill in the art who review this disclosure that these terms are intended to allow a description of certain features described without restricting the scope of these features to any numerical ranges provided. Accordingly, these terms should be interpreted as indicating that insubstantial or inconsequential modifications or alterations of the subject matter described and are considered to be within the scope of the disclosure.

[00114] It should be understood that numerous changes, modifications, and alternatives of the preceding disclosure can be made without departing from the scope of the disclosure. The preceding description, therefore, is not meant to limit the scope of the disclosure. It is also contemplated that structures and features in the present examples can be altered, rearranged, substituted, deleted, duplicated, combined, or added to each other.

[00115]
The articles "the," "a," and "an" are not necessarily limited to mean only one, but rather are inclusive so as to include, optionally, multiple such elements.

Claims

1. A method of recovering heavy oil from a subterranean reservoir via a thermal recovery well pair, the thermal recovery well pair comprising an injection well, for injecting injection vapor into the subterranean reservoir to form a vapor chamber, and a production well, at an elevation below the injection well, for recovering heavy oil from the subterranean reservoir, the method comprising:
providing an infill well in an area laterally spaced apart from the thermal recovery well pair;
injecting an injected fluid via the infill well into the subterranean reservoir at a time during which the injected fluid establishes a horizontal planar communication path between the infill well and the vapor chamber, the horizontal planar communication path enabling substantially horizontal planar distribution of the injection vapor within the subterranean reservoir;
producing a produced fluid from the infill well to at least partially recover the heavy oil from the horizontal planar communication path, the horizontal planar communication path providing horizontal planar communication; and producing the heavy oil from at least one of (i) the infill well after the horizontal planar communication has been established and (ii) the production well to recover the heavy oil from the subterranean reservoir.

2. The method of claim 1, wherein the time is upon formation of the vapor chamber and prior to the vapor chamber reaching an overburden of the subterranean reservoir.

3. The method of claim 1, wherein the time is after the injection vapor causes a primarily minimum vertical stress state in a reservoir matrix of the subterranean reservoir.

4. The method of any one of claims Ito 3, wherein the thermal recovery well pair comprises two thermal recovery well pairs and the infill well is between the two thermal recovery well pairs and laterally spaced apart from each of the two thermal recovery well pairs.

5. The method of any one of claims 1 to 3, wherein the thermal recovery well pair comprises more than two thermal recovery well pairs and the infill well comprises infill wells, wherein one of the infill wells is between two of the more than two thermal recovery well pairs and is laterally spaced apart from each of the two of the more than two thermal recovery well pairs.

6. The method of claim 1, further comprising:
repeatedly injecting the injected fluid and producing the produced fluid.

7. The method of any one of claims Ito 6, wherein injecting the injected fluid comprises:
injecting a mobilizing fluid via the infill well into the subterranean reservoir; and injecting an infill well vapor via the infill well into the subterranean reservoir.

8. The method of claim 7, wherein the mobilizing fluid is selected from a group consisting of cold water, hot water, cold liquid hydrocarbon solvent, hot liquid hydrocarbon solvent, steam, wet steam, gas and a mixture of at least two of cold water, hot water, cold liquid hydrocarbon solvent, hot liquid hydrocarbon solvent, steam, wet steam and gas and the infill well vapor is selected from a group consisting of steam, solvent and steam-solvent mixture.

9. The method of any one of claims 7 to 8, further comprising:
repeatedly injecting the infill well vapor and producing the produced fluid.

10. The method of any one of claims 1 to 6, wherein the injected fluid comprises solvent and the method further comprises:
cyclically injecting the injected fluid, and producing the produced fluid to create solvent fingers, wherein the solvent fingers form, at least in part, the horizontal planar communication path.

11. The method of any one of claims 1 to 10, wherein injecting the injected fluid and producing the produced fluid are performed by at least one of cyclic steam stimulation and cyclic solvent stimulation.

12. The method of any one of claims 1 to 11, wherein the injected fluid is injected at a pressure that creates horizontal fractures in a reservoir matrix of the subterranean reservoir.

13. The method of any one of claims 1 to 12, wherein the injected fluid is selected from a group consisting of cold water, hot water, cold liquid hydrocarbon solvent, hot liquid hydrocarbon solvent, steam, wet steam, gas and a mixture of at least two of cold water, hot water, cold liquid hydrocarbon solvent, hot liquid hydrocarbon solvent, steam, wet steam and gas.

14. The method of any one of claims 1 to 13, wherein the thermal recovery well pair is a steam assisted gravity drainage well pair.

15. The method of any one of claims 1 to 14, wherein the infill well is at an elevation that is one of at and below the elevation of the production well.

16. The method of any one of claims 1 to 15, further comprising completing the infill well with flow control devices configured to evenly distribute the injected fluid.

17. The method of any one of claims 1 to 16, wherein the injection vapor is selected from a group consisting of steam, solvent and steam-solvent mixture.

18. A method of recovering heavy oil from a subterranean reservoir comprising:
providing two thermal recovery well pairs laterally spaced apart from each other, each of the two thermal recovery well pairs comprising an injection well, for injecting injection vapor into the subterranean reservoir, and a production well, at an elevation below the injection well, for removing heavy oil from the subterranean reservoir, the injection vapor forming a vapor chamber above each of the two thermal recovery well pairs;
providing an infill well between and laterally spaced apart from each of the two thermal recovery well pairs;
injecting the injection vapor from each of the injection wells to form the vapor chamber above each of the two thermal recovery well pairs;
establishing horizontal planar communication between the infill well and the vapor chambers of the two thermal recovery well pairs by injecting an injected fluid via the infill well into the subterranean reservoir after forming of the vapor chambers; and producing the heavy oil from the production wells.

19. The method of claim 18, wherein establishing the horizontal planar communication comprises:
alternately operating the infill well between an injection mode to inject the injected fluid and a production mode to produce a produced fluid from the infill well until the horizontal planar communication is established.

20. The method of claim 18, further comprising:
operating the infill well in a production mode to produce a produced fluid after establishing the horizontal planar communication.

21. The method of claim 18, further comprising:
operating the infill well in one of a production mode to produce a produced fluid and an injection mode to inject the injected fluid after establishing the horizontal planar communication, wherein operating the infill well in the injection mode occurs at least one of:
(i) at predetermined intervals to ensure the horizontal planar communication remains established; and (ii) at requested times when there is a blockage in the horizontal planar communication.

22. The method of any one of claims 18 to 21, wherein establishing the horizontal planar communication comprises:
injecting a mobilizing fluid via the infill well into the subterranean reservoir;
injecting an infill well vapor via the infill well into the subterranean reservoir; and producing a produced fluid from the infill well.

23. The method of claim 22, wherein the mobilizing fluid is selected from a group consisting of cold water, hot water, cold liquid hydrocarbon solvent, hot liquid hydrocarbon solvent, steam, wet steam, gas and a mixture of at least two of cold water, hot water, cold liquid hydrocarbon solvent, hot liquid hydrocarbon solvent, steam, wet steam and gas and wherein the infill well vapor is selected from a group consisting of steam, solvent and steam-solvent mixture.

24. The method of any one of claims 22 to 23, wherein establishing the horizontal planar communication further comprises:
repeatedly injecting the infill well vapor and producing the produced fluid until the horizontal planar communication is established.

25. The method of any one of claims 18 to 24, wherein establishing the horizontal planar communication comprises:
injecting the injected fluid from the infill well at a time after the injection vapor causes a primarily minimum vertical stress state in a reservoir matrix of the subterranean reservoir.

26. The method of any one of claims 18 to 24, wherein establishing the horizontal planar communication further comprises:
injecting the injected fluid from the infill well at a time during which the injected fluid establishes horizontal planar communication paths between the infill well and the vapor chambers enabling a substantially horizontal planar distribution of the injection vapor within the subterranean reservoir.

27. The method of any one of claims 18 to 26, wherein the injected fluid is injected at a pressure that creates horizontal fractures in a reservoir matrix of the subterranean reservoir.

28. The method of any one of claims 18 to 27, wherein the injected fluid is selected from a group consisting of cold water, hot water, cold liquid hydrocarbon solvent, hot liquid hydrocarbon solvent, steam, wet steam, gas and a mixture of at least two of cold water, hot water, cold liquid hydrocarbon solvent, hot liquid hydrocarbon solvent, steam, wet steam and gas.

29. The method of any one of claims 18 to 28, wherein the injection vapor is selected from a group consisting of steam, solvent and steam-solvent mixture.

30. The method of any one of claims 18 to 29, further comprising completing the infill well with flow control devices configured to evenly distribute the injected fluid.

31. The method of any one of claims 18 to 30, wherein establishing the horizontal planar communication is performed by at least one of cyclic steam stimulation and cyclic solvent stimulation.