HARVESTING RESOURCE FROM VARIABLE PAY INTERVALS

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the priority benefit of Canadian Patent Application 2,749,437 filed Aug. 17, 2011 entitled HARVESTING RESOURCE FROM VARIABLE PAY INTERVALS, the entirety of which is incorporated by reference herein.

FIELD

The present techniques relate to the use of well pairs to harvest resources. Specifically, techniques are disclosed for designing gravity drainage well pairs to increase the recovery of resource from a reservoir.

BACKGROUND

This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present techniques. This discussion is believed to assist in providing a framework 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.

Modern society is greatly dependant on the use of hydrocarbons for fuels and chemical feedstocks. Hydrocarbons are generally found in subsurface rock formations that can be termed “reservoirs.” Removing hydrocarbons from the reservoirs depends on numerous physical properties of the rock formations, such as the permeability of the rock containing the hydrocarbons, the ability of the hydrocarbons to flow through the rock formations, and the proportion of hydrocarbons present, among others.

Easily harvested sources of hydrocarbon are dwindling, leaving less accessible sources to satisfy future energy needs. However, as the costs of hydrocarbons increase, these less accessible sources become more economically attractive. For example, the harvesting of oil sands to remove hydrocarbons has become more extensive as it has become more economical. The hydrocarbons harvested from these reservoirs may have relatively high viscosities, for example, ranging from 8 API, or lower, up to 20 API, or higher. Accordingly, the hydrocarbons may include heavy oils, bitumen, or other carbonaceous materials, collectively referred to herein as “heavy oil,” which are difficult to recover using standard techniques.

Several methods have been developed to remove hydrocarbons from oil sands. For example, strip or surface mining may be performed to access the oil sands, which can then be treated with hot water or steam to extract the oil. However, deeper formations may not be accessible using a strip mining approach. For these formations, a well can be drilled to the reservoir and steam, hot air, solvents, or combinations thereof, can be injected to release the hydrocarbons. The released hydrocarbons may then be collected by the injection well or by other wells and brought to the surface.

A number of techniques have been developed for harvesting heavy oil from subsurface formations using thermal recovery techniques. Thermal recovery operations are used around the world to recover liquid hydrocarbons from both sandstone and carbonate reservoirs. These operations include a suite of steam based in situ thermal recovery techniques, such as cyclic steam stimulation (CSS), steam flooding and steam assisted gravity drainage (SAGD) as well as surface mining and their associated thermal based surface extraction techniques.

The CSS process may raise the steam injection pressure above the formation fracturing pressure to create fractures within the formation and enhance the surface area access of the steam to the heavy oil, although CSS may also be practiced at pressures that do not fracture the formation. The steam raises the temperature of the heavy oil during a heat soak phase, lowering the viscosity of the heavy oil. The injection well may then be used to produce heavy oil from the formation. The cycle is repeated until the cost of injecting steam becomes uneconomical, for instance if the cost is higher than the money made from producing the heavy oil. However, successive steam injection cycles reenter earlier created fractures and, thus, the process becomes less efficient over time. CSS is generally practiced in vertical wells, but systems are operational in horizontal wells.

Solvents may also be used in combination with steam in CSS processes, such as in mixtures with the steam or in alternate injections between steam injections. Further, solvents can be used in cyclic recovery processes in the absence of thermal sources. For example, a hydrocarbon solvent may be injected into a reservoir to reduce the viscosity of a heavy oil. During a soak phase, the hydrocarbon solvent is allowed to mix with the heavy oil at an elevated pressure. The pressure in the reservoir can then be reduced to allow at least a portion of the hydrocarbon solvent to flash, providing a solvent gas drive to assist in removing the heavy oil from the reservoir. The cycles may be repeated as long as economical production is achieved.

Another group of techniques is based on a continuous injection of steam through a first well to lower the viscosity of heavy oils and a continuous production of the heavy oil from a lower-lying second well. Such techniques may be termed “steam assisted gravity drainage” or SAGD.

In SAGD, two horizontal wells are completed into the reservoir. The two wells are first drilled vertically to different depths within the reservoir. Thereafter, using directional drilling technology, the two wells are extended in the horizontal direction that result in two horizontal wells, vertically spaced from, but otherwise vertically aligned with the other. Ideally, the production well is located above the base of the reservoir but as close as practical to the bottom of the reservoir, and the injection well is located vertically 10 to 30 feet (3 to 10 meters) above the horizontal well used for production.

The upper horizontal well is utilized as an injection well and is supplied with steam from the surface. The steam rises from the injection well, permeating the reservoir to form a vapor chamber that grows over time towards the top of the reservoir, thereby increasing the temperature within the reservoir. The steam, and its condensate, raise the temperature of the reservoir and consequently reduce the viscosity of the heavy oil in the reservoir. The heavy oil and condensed steam will then drain downward through the reservoir under the action of gravity and may flow into the lower production well, whereby these liquids can be pumped to the surface. At the surface of the well, the condensed steam and heavy oil are separated, and the heavy oil may be diluted with appropriate light hydrocarbons for transport by pipeline.

A number of variations of the SAGD process have been developed in an attempt to increase the productivity of the process. Such processes may include new well placement techniques and tools used to enhance production of the heavy oil. In other variations, extensions similar to those used in CSS, such as including solvents in the process, have been made.

Similarly, Canadian Patent No. 2,591,498 and corresponding U.S. Pat. No. 7,556,099 to Arthur, et al. discloses a recovery process that utilizes in-fill wells. In the method, a first injector-producer well pair is operated under a substantially gravity-controlled recovery process, forming a first mobilized zone. A second injector-producer well pair is also operated under a substantially gravity-controlled recovery process, forming a second mobilized zone. An in-fill well is provided in a bypassed region, formed between the adjacent well pairs. When the first mobilized zone and the second mobilized zone merge to form a common mobilized zone, the in-fill well can be operated to establish fluid communication between the in-fill well and the common mobilized zone. Accordingly, the in-fill well and the adjacent well pairs may be operated under a substantially gravity-controlled recovery process to recover heavy oil from the in-fill well.

In another example of the use of in-fill wells, U.S. Patent Application Publication No. 2009/0288827 by Coskuner, filed Nov. 26, 2009, discloses a process for recovering heavy oil from oil sands. In the process, CSS is first used in a series of horizontal wells in the reservoir. SAGD is then used with a vertically-spaced horizontal well pair in which one well in each well pair is part of the series of wells to which CSS was applied, and oil is produced from at least one single well in the series of wells. In this case, each single well is adjacent to and offset from at least one of the well pairs. The method can then include applying a SAGD injection to an injection well of each well pair and producing oil from a production well of each well pair and from the single well.

SAGD designs often stress the need to minimize the pressure drop that occurs along the length of the liners of the injection and production wells. Current industry practice is to use as a target a pressure drop in the liners, irrespective of the length of the liners, for example, of 50 kPa. This corresponds to a liquid head of about five meters, which corresponds to the typical separation between SAGD injection and production wells. To achieve this target, current injector designs include splitting steam injection between the two ends of the liner by including a tubing string that extends to the toe of the liner. Other designs increase the liner diameter as the liner length and, thus, the steam demand increase. Increasing the liner diameter as the operating pressure decreases and the physical volume of the steam travelling through the liner increases. In some designs, the steam injection and production locations in each liner are offset, so that portions of the pressure drops occurring in the injection and production wells cancel. In yet other designs, the toe tubing string can be repositioned and the steam injection rebalanced between the two injection strings to account for the changes in the hydraulic diameters along the liner length that result. Further, in some designs, once sufficient steam injectivity into the reservoir exists, a tubing string with a series of limited entry perforations is used to distribute the steam at multiple locations along the annulus. Further, in other designs, the open area between the liner and reservoir can be constrained such that the pressure drop within the liner is not transferred to the reservoir.

It is current industry practice that when gravity drainage is the dominant recovery mechanism the production liner should be drilled as flat as possible and the injection and production wells should have matched lengths. This arrangement decreases the potential for the steam to be coned into the production well at high points along the liner trajectory. Reproduction of the steam vapor represents a needless increase in operating costs. However, in situations where the base of pay is not flat, a flat production liner trajectory can result in significant quantities of otherwise recoverable resource being located beneath the depth of the producer. As a result, recovering this bypassed resource will require a future investment in new wells or sidetrack completions from the existing wells.

SUMMARY

An embodiment described herein provides a method for improving recovery from a subsurface hydrocarbon reservoir. The method includes mapping a base of a reservoir to determine a region that holds hydrocarbons and accessing the region by a serpentine well pair. The serpentine well pair includes a production well at a first elevation and an injection well at a higher elevation. The production well is drilled with a variable trajectory to follow at least a portion of the base of the reservoir. Further, at least a portion of the production well includes a liner with no perforations.

Another embodiment provides a system for harvesting resources from a reservoir. The system includes a reservoir that holds hydrocarbons. A serpentine well pair is included in the system, wherein the serpentine well pair comprises a production well at a first elevation and an injection well at a higher elevation. The production well has a variable trajectory to follow at least a portion of the base of the reservoir and at least a portion of the production well includes a liner with no perforations.

Another embodiment provides a method for drilling a well in a reservoir. The method includes planning a well trajectory for a serpentine well pair. The production well is drilled using lateral displacements and vertical displacements to follow a base of a pay interval in the reservoir. The production well is completed with a liner that includes perforations in regions comprising a hydrocarbon, and at least a portion of the production well has no perforations.

DESCRIPTION OF THE DRAWINGS

The advantages of the present techniques are better understood by referring to the following detailed description and the attached drawings, in which:

FIG. 1 is a drawing of a steam assisted gravity drainage (SAGD) process 100 used for accessing hydrocarbon resources in a reservoir 102;

FIG. 2 is a cross section of a well interval showing the presence of separate production intervals in a reservoir;

FIG. 3 is a schematic illustrating an injection liner having a tapered section to improve the movement through a wellbore;

FIGS. 4(A), (B), and (C) are North-South cross-sectional views of different production intervals in a reservoir;

FIGS. 5(A), (B), and (C) are cross-sectional views illustrating the placement of standard well-pairs in the cross-sectional views of FIGS. 4(A), (B), and (C), respectively;

FIG. 6 is a cross-sectional view illustrating the placement of a curving SAGD well-pair in the cross-sectional view of FIG. 4(A);

FIGS. 7(A), (B), and (C) are cross-sectional views illustrating various configurations that may be used for the placement of serpentine well-pairs in the cross-sectional view of FIG. 4(A);

FIG. 9 is a process flow diagram of a method for completing serpentine well-pairs that access resources that may be bypassed by SAGD well pairs having a flat trajectory.

DETAILED DESCRIPTION

In the following detailed description section, specific embodiments of the present techniques are described. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present techniques, this is intended to be for exemplary purposes only and simply provides a description of the exemplary embodiments. Accordingly, the techniques are not limited to the specific embodiments described below, but rather, include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.

At the outset, for ease of reference, certain terms used in this application and their meanings as used in this context are set forth. 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 techniques are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments, and terms or techniques that serve the same or a similar purpose are considered to be within the scope of the present claims.

As used herein, the term “base” indicates a lower boundary of the resources in a reservoir that are practically recoverable, by a gravity-assisted drainage technique, for example, using an injected mobilizing fluid, such as steam, solvents, hot water, gas, and the like. The base may be considered a lower boundary of the pay interval. 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 impermeable, impede the formation of fluid communication between a well on one side and a well on the other side. Such layers may include broken shale, mud, silt, and the like. The resources within the reservoir may extend below the base, but the resources below the base may not be recoverable with gravity-assisted techniques.

“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 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 metals content, while small, must be removed to avoid contamination of the product synthetic crude oil (SCO). Nickel can vary from less than 75 ppm (part per million) to more than 200 ppm. Vanadium can range from less than 200 ppm to more than 500 ppm. The percentage of the hydrocarbon types found in bitumen can vary. As used herein, the term “heavy oil” includes bitumen, as well as lighter materials that may be found in a sand or carbonate reservoir.

As used herein, two locations in a reservoir are in “fluid communication” when a path for fluid flow exists between the locations. For example, the establish of fluid communication between a lower-lying production well and a higher injection well may allow material mobilized from a steam chamber above the injection well to flow down to the production well from collection and production. As used herein, a fluid includes a gas or a liquid and may include, for example, a produced hydrocarbon, an injected mobilizing fluid, or water, among other materials.

As used herein, a “cyclic recovery process” uses an intermittent injection of a mobilizing fluid selected to lower the viscosity of heavy oil in a hydrocarbon reservoir. The injected mobilizing fluid may include steam, solvents, gas, water, or any combinations thereof. After a soak period, intended to allow the injected material to interact with the heavy oil in the reservoir, the material in the reservoir, including the mobilized heavy oil and some portion of the mobilizing agent may be harvested from the reservoir. Cyclic recovery processes use multiple recovery mechanisms, in addition to gravity drainage, early in the life of the process. The significance of these additional recovery mechanisms, for example dilation and compaction, solution gas drive, water flashing, and the like, declines as the recovery process matures. Practically speaking, gravity drainage is the dominant recovery mechanism in all mature thermal, thermal-solvent and solvent based recovery processes used to develop heavy oil and bitumen deposits. For this reason the approaches disclosed here are equally applicable to all recovery processes in which, at the current stage of depletion, gravity drainage is the dominant recovery mechanism.

“Facility” as used in this description is a tangible piece of physical equipment through which hydrocarbon fluids are either produced from a reservoir or injected into a reservoir, or equipment which 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 reservoir and its delivery outlets. Facilities may comprise production wells, injection wells, well tubulars, wellhead 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.

“Heavy oil” includes oils which are classified by the American Petroleum Institute (API), as heavy oils or extra heavy oils. In general, a heavy oil has an API gravity between 22.3° (density of 920 kg/m3 or 0.920 g/cm3) and 10.0° (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° (density greater than 1,000 kg/m3 or greater than 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 thermal 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 fluids by steam, hot water flooding, or gravity is possible. The reduced viscosity makes the drainage quicker and therefore directly contributes to the recovery rate.

A “hydrocarbon” is an organic compound that primarily includes the elements hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number of other elements may be present in small amounts. As used herein, hydrocarbons generally refer to components found in heavy oil, or other oil sands.

“Permeability” is the capacity of a rock to transmit fluids through the interconnected pore spaces of the rock. The customary unit of measurement for permeability is the millidarcy.

As used herein, a “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 oil, gas, or coal, among others. Reservoirs can vary in thickness from less than one foot (0.3048 m) to hundreds of feet (hundreds of m). The resource is generally a hydrocarbon, such as a heavy oil impregnated into a sand bed.

As used herein, “serpentine well pair” indicates that at least one of the wells in the well pair uses lateral displacements, vertical displacements, or both to follow a base of the pay interval in a reservoir. Further, serpentine well pairs include well pairs in which one of the paired wells extends past the other well.

As discussed in detail above, “Steam Assisted Gravity Drainage” (SAGD), is a thermal recovery process in which steam, or combinations of steam and solvents, is injected into a first well to lower a viscosity of a heavy oil, and fluids are recovered from a second well. Both wells are generally horizontal in the formation and the first well lies above the second well. Accordingly, the reduced viscosity heavy oil flows down to the second well under the force of gravity, although pressure differential may provide some driving force in various applications.

“Substantial” when used in reference to a quantity or amount of a material, or a specific characteristic thereof, 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.

As used herein, “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 fluids, such as hot water, wet steam, dry steam, or solvents alone, or in any combinations, to lower the viscosity of the hydrocarbon. Such processes may include subsurface processes, such as cyclic steam stimulation (CSS), cyclic solvent stimulation, steam flooding, solvent injection, and SAGD, among others, and processes that use surface processing for the recovery, such as sub-surface mining and surface mining. Any of the processes referred to herein, such as SAGD may be used in concert with solvents.

A “well” is a hole in the subsurface made by drilling or inserting a conduit into the subsurface. A well may have a substantially circular cross section or any other cross-sectional shape, such as an oval, a square, a rectangle, a triangle, or other regular or irregular shapes. As used herein, the term “wellbore”, when referring to an opening in the formation, may be used interchangeably with the term “well”.

Overview

Current techniques for harvesting heavy oils may bypass a substantial amount of hydrocarbon resources in the reservoir. The location and quantity of resources, or unswept hydrocarbons, bypassed by the current recovery processes is a function of several factors. These include geologic variability, well placement decisions, operational decisions, and well failures, among others. For example, the current industry practice for well pairs used for steam assisted gravity drainage (SAGD) is to keep the well trajectories as flat as possible, in order to minimize the risk of steam, or other mobilizing fluids, from crossing over to the production well at a high point along a trajectory. Thus, the SAGD wells may bridge low points in a reservoir without accessing the hydrocarbons present. Similarly, the current approaches to using in-fill wells to recover bypassed hydrocarbons use horizontal wells placed between SAGD well pairs, wherein the horizontal wells are kept to flat trajectories for essentially the same reasons.

Embodiments described herein relate to a method for improving recovery from a subsurface hydrocarbon reservoir. Regions are identified within the reservoir that may contain significant accumulations of unswept hydrocarbons after a normal SAGD process. Serpentine well pairs can then be designed to pass through the regions. The placement and completion of the serpentine well pairs can be optimized to maximize the recovery of the unswept hydrocarbons. For example, the serpentine wells may be completed to follow a base of the reservoir. Further, a production well may travel through a non-pay interval to connect two pay intervals. In areas where the production well has an increasing trajectory, the production well liner may not have perforations, e.g., being completed with blank pipe. In addition, an injection well may extend beyond a production wells into raised areas containing resources, helping the resources to drain to the production wells. A tapered liner may be used in embodiments to assist in following the curving wells. As noted herein, the base of the reservoir represents a practical lower limit of the hydrocarbons that may be recoverable by a gravity-assisted process.

In embodiments, various techniques are used to prevent excess reproduction of injected mobilizing fluids used in the hydrocarbon recovery process. These techniques may include process design and control or the selective obstruction of portions of the liner in the serpentine well pairs. In some embodiments, a geometric pattern may be used for placing the in-fill wells.

Although, for simplicity of explanation, SAGD is used to describe the techniques herein, the techniques are equally applicable to all recovery processes in which gravity drainage is the dominant recovery mechanism. For example, in an embodiment, a serpentine well pair may be completed into a reservoir to enhance recovery of hydrocarbons. Further, the techniques may be used in recovery processes that use solvent, or steam and solvent mixtures, to mobilize hydrocarbons. Thus, the injected mobilizing fluid used to harvest the hydrocarbons may include steam, solvents, gas, steam and solvent mixtures, and any combinations thereof, including different mobilizing fluids at different points in the life of a reservoir.

FIG. 1 is a drawing of a steam assisted gravity drainage (SAGD) process 100 used for accessing hydrocarbon resources in a reservoir 102. In the SAGD process 100, steam 104 can be injected through injection wells 106 to the reservoir 102. As previously noted, the injection wells 106 may be horizontally drilled through the reservoir 102. Production wells 108 may be drilled horizontally through the reservoir 102, with a production well 108 underlying each injection well 106. Generally, the injection wells 106 and production wells 108 will be drilled from the same pad 110 at the surface 112. This may make it easier for the production well 108 to track the injection well 106. However, in some embodiments the wells 106 and 108 may be drilled from different pads 110.

The injection of steam 104 into the injection wells 106 may result in the mobilization of hydrocarbons 114, which may drain to the production wells 108 and be removed to the surface 112 in a mixed stream 116 that can contain hydrocarbons, condensate and other materials, such as water, gases, and the like. As described herein, screen assemblies may be used on the injection wells 106, for example, to throttle the inflow of injectant vapor to the reservoir 102. Similarly, screen assemblies may be used on the production wells 108, for example, to decrease sand entrainment.

The hydrocarbons 114 may form a triangular shaped drainage chamber 118 that has the production well 108 located at a lower apex. The mixed stream 116 from a number of production wells 108 may be combined and sent to a processing facility 120. At the processing facility 120, the water and hydrocarbons 122 can be separated, and the hydrocarbons 122 sent on for further refining. Water from the separation may be recycled to a steam generation unit within the facility 120, with or without further treatment, and used to generate the steam 104 used for the SAGD process 100.

In prior SAGD processes, the production wells 108 often had a segment that was relatively flat and, in some circumstances, had a slight upward slope from the heel 126, at which the pipe branches to the surface, to the toe 128, at which the pipe ends. However, the previous configuration of the production well 108 could result in bridging over some sections 132 of the reservoir 102, leaving hydrocarbons behind. These sections 132 can be caused by natural variations, or rugosity, in the base 134 of the reservoir, for example, caused by karsting, depositional facies, and erosional incisements.

In embodiments described herein, the unswept resources in these sections 132 may be accessed by making the trajectories of the production wells 108, or both the production 108 and injection wells 106 follow the base 134 in a serpentine fashion. Any number of other configurations may be used as discussed with respect to FIGS. 6-8. As used herein, any of these variations, including systems in which only the production well 108 follows the base 134 of the reservoir and in which one well or the other extends out beyond the other well, is termed a serpentine well pair 136. The serpentine well pairs 136 can be directionally drilled to follow the base 134 of the reservoir 102, for example, moving laterally and vertically towards and through the sections 132, permitting hydrocarbons to be harvested from areas that would otherwise be bypassed. High points in the production wells 108 may be left uncompleted, for example, by being left as blank pipe segments.

FIG. 2 is a cross section of a well interval showing the presence of separate production intervals 202 and 204 in a reservoir 102. The production intervals 202 and 204 are formed by a limestone layer 206 that has a high spot 208 blocking flow of hydrocarbon between the production intervals 202 and 204. In the low points of the production intervals 202 and 204, the production well 108 can be completed, for example, with screens, perforations, mesh, or other openings, to harvest hydrocarbons from the production intervals 202 and 204. As used herein, the production intervals 202 and 204 containing the completed well trajectories may be termed subsurface drainage boxes.

Other portions 210 of the trajectory of the production well 108 can be formed using blank pipe, e.g., without perforations. In contrast, all of the injection well 106 may be completed, allowing injection of the mobilizing agent 212, such as steam, throughout the reservoir 102. Mobilized hydrocarbons 214 can then flow down to the production intervals 202 and 204. The liners of the wells 106 and 108 may have difficulty following the complex trajectory or passing over sand bridges that have formed in the well. In some embodiments, this is resolved by tapering the liners, as discussed with respect to FIG. 3.

FIG. 3 is a schematic illustrating an injection liner 300 having a tapered section 302 to improve the movement through a wellbore. The tapered section 302 may include a single section of pipe having a smaller diameter than the liner, or may be a series of smaller diameter pipe segments at the end of the liner. For example, the tapered segment may be a 14 cm in diameter pipe segment attached to an 18 cm in diameter liner section using a 14 cm×18 cm crossover. In this example, a toe-tubing string 304, which carries steam 306 to the end of the liner 300, is placed within the full sized-section 308 of the liner 300. The tapered section 302 can be used to follow a rising trajectory 310, for example, of about 0.5 degrees, allowing steam 306 to flow up into the tapered section 302 and water 312 to flow down from the tapered section 302. Similar tapering may be used for liners in production wells, allowing complex trajectories to be drilled for the wells. The tapered section 302 does not have to be long to make following a trajectory easier, for example, 50 m to 100 m may be sufficient.

FIGS. 4(A), (B), and (C) are North-South cross-sectional views of different production intervals 402, 404, and 406 in a reservoir 102. In these cross-sections the base 408 and top 410 of the pay interval 412 deemed to be acceptable for exploitation with SAGD are noted. As previously noted, the rugosity of the base 408 can be due to a combination of factors, for example, karsting, changes in depositional facies, or erosional incisements, among others.

FIGS. 5(A), (B), and (C) are cross-sectional views illustrating the placement of standard well-pairs in the cross-sectional views of FIGS. 4(A), (B), and (C), respectively. In each of these cross-sections a SAGD well pair 502, drilled with a flat trajectory, has been added. In all three cases, a significant quantity 504 of exploitable resource has been stranded beneath the trajectory of the SAGD well pair 502.

FIG. 6 is a cross-sectional view illustrating the placement of a curving SAGD well-pair 602 in the cross-sectional view of FIG. 4(A), in accordance with previous studies. In this case the SAGD well-pair 602 has been drilled such that it tracks the base 408 of the pay interval 412. The expected benefit with this profile is lost by restricting production from the production well 108 to prevent the steam chamber from coning into the high point of the trajectory of the production well 108. This will result in fluid accumulating above the remainder of the well trajectory, effectively decreasing the effective height of the steam chamber. If, as drawn here, the height of the liquid sump 604 exceeds the depth of the injection well 106, the accumulated fluids can impair steam injection at these locations, further impeding the SAGD operation.

FIGS. 7(A), (B), and (C) are cross-sectional views illustrating various configurations that may be used for the placement of serpentine well-pairs in the cross-sectional view of FIG. 4(A). In these embodiments, the injection well 106 can be used as a “hot finger” that results in the accelerated depletion of a reservoir 102. In all three cases shown in FIG. 7, the completed portion of the trajectory of the production well 108 remains confined to the deepest pay, while the trajectory of the injection well 106 has been extended beyond the toe of the production liner into an area of thinner pay interval.

In FIG. 7(A), the profile of the injection well 106 continues to slowly raise though the pay interval 412. This “toe up” configuration enables steam to be present throughout the entire length of the injector liner extension 702, without requiring an injection tubing string to be present in the toe up section. As the steam condenses, the condensate can travel back along liner string under the influence of gravity. The heated oil surrounding the injector extension can also drain under the influence of gravity along the heated pathway back to the toe of the production well. Steam present in the injector liner will leave the injector to occupy the space vacated by the oil thereby causing the steam chamber to rapidly grow into the area surrounding the toe up injector liner. This configuration may cause a rapid drainage of the resource from the thinner area of the pay interval 412.

In FIG. 7(B) the slow rise of the injector liner extension 702 has been interrupted by a series of flat or dipping sections 704 that will result in a slower rate of heating in the extension area. For example, in a dipping section 704 of the injector liner extension 702, the condensed steam cannot drain out of the dipping section 704 until the steam chamber has had the opportunity to extend as far as the first liner access point beyond the location of the dipping section 704. Once this occurs, the condensate that has accumulated in the dipping section 704 can drain from the liner and steam to access the next increment of toe up liner that ends at the next dip in the injector profile. This may result in a slower drainage of resource from the thinner section of the pay interval 412.

In FIG. 7(C) the profile of the injector liner extension 702 initially rises to stay within the pay interval 412 and then remains flat. This configuration allows some steam to be present throughout the entire length of the injector liner extension, without requiring an injection tubing string to be present. The flat well profile will slow the drainage of the condensate from the injector liner extension 702 and the drainage of oil from the heated reservoir surrounding the injector liner extension 702. As a result, the long term rate of heat penetration and resource depletion should be between that expected with the configurations shown in FIGS. 7(A) and 7(B). In all three cases, as shown in FIGS. 7(A), 7(B), and 7(C), the liquid sump 604 is slightly above the production well 108. If the production well 108 rises above a target depth for the liquid sump 604, higher sections may be completed with blank pipe to prevent the liquid sump 604 from getting deeper than the target depth.

FIGS. 8(A) and (B) are cross-sectional views illustrating various configurations that may be used for the placement of serpentine well-pairs in the cross-sectional views of FIGS. 4(B) and (C), respectively. The configurations in FIG. 8 show that the injection well 106 can be used as a “hot finger” that results in the accelerated depletion of reservoirs similar to those shown in FIG. 7.

In FIG. 8(A), the completions in the liner, e.g., perforations in the production well 108, stops at the end of the structural low 802. The injector profile on either side of the structural low has been modified to allow steam to accumulate, condense and drain from these non-horizontal sections, thereby accelerating recovery.

In FIG. 8(B) the production well 108 is drilled through an interval 804 of poor reservoir quality, while the injection well 106 passes above the interval 804. The profile of the injection well 106 is modified to ensure that steam is able to accumulate, condense and drain in the section above the interval 804, thereby accelerating recovery from the thinner good quality reservoir present above the interval 804 of poor quality. The two open portions of the production well liner that allow inflow are confined to the two structural low areas 806.

FIG. 9 is a process flow diagram of a method for completing serpentine well-pairs that access resources that may be bypassed by SAGD well pairs having a flat trajectory. The method 900 starts at block 902 with the delineation of the one or more pay intervals expected to be developed over the life of the project. Reservoir delineation typically occurs through the combined use of delineation wells, remote sensing technologies such as 2-dimensional and 3-dimensional seismic analyses, studies of modern analogs, and outcrop studies of the target reservoir, if parts of the reservoir outcrop on surface. Other reservoirs with comparable depositional settings may be used to provide insight into the delineation.

Delineation wells are used to collect core samples of the target reservoir and open hole and cased hole log data. The core samples are further used to gain an understanding of the depositional settings present in the reservoir, porosity and oil content distributions, horizontal and vertical permeability distributions, oil density and viscosity distributions, sand grain size analyses and reservoir rock samples that can be used to understand how the reservoir material will respond to heating with steam and/or water or extended exposure to a solvent. Remote sensing technologies, modern reservoir analogs, and outcrop studies allow the prediction of the spatial distribution of the geologic attributes and fluid properties in the reservoir. As used herein, modern reservoir analogs include modern regions that have the same depositional environment as the older buried reservoir, such as river systems, coastal areas, and the like.

Additional data can be collected to understand various other properties of the reservoir for the modeling. Such properties include the ability of the reservoir caprock to withstand changes in pressure associated with an injection of injectant when an in-situ recovery process is applied. Other properties include the initial pressure distribution in the reservoir and surrounding strata. Pressure properties in the reservoir collected may include the presence and areal extend of any pressure sinks, such as top gas, top water, or bottom water. Further, information can be collected on any interstitial intervals within the reservoir. Such interstitial intervals may have initial enhanced water mobility and may be present within, or directly adjacent, to the oil-bearing sections. A determination may be made of the locations, and capacities, of water make-up sources and water disposal intervals.

These data are used to create a geologic model for each reservoir that is expected to be included as part of the overall development. The geologic models are usually constructed using a geologic modeling software program, such as the Petrel program available from the Schlumberger corporation, among others. The available open hole and cased hole log, core, 2-D and 3-D seismic data, and knowledge of the depositional environment setting are used in the construction the geologic model which can include many millions of individual cells of sizes specified by the user.

The geologic model can then be used to identify the region of the resource to be included in the initial phase of the development. Criteria for this decision include pay thickness, pay cleanliness (e.g., the absence of shale lenses), the number and size of pressure sinks, if any, and the like. The model also allows the construction of a structural map of the position of the base of the pay interval. This map may use sea level as a reference point, as the ground level above the reservoir will not be flat.

Thus, at block 904, serpentine well pairs can be designed using the available geologic model. The depth and lateral offset of the trajectories of the serpentine wells vary such that a portion of each serpentine well can intercept one or more of the low-lying hydrocarbon intervals near the base. To perform this function, surface constraints are identified that may limit the position of surface drilling locations and, thus, the specific layout of the completed production liners in low regions of the reservoir, i.e., the subsurface drainage boxes.

For each subsurface drainage box, the model is used to identify the portions of the well trajectory that are the deepest. These will become the desired locations for the production completion intervals. The model is also used to identify the portions of the well trajectory that are the shallowest. These will become the desired locations for the inclusion of non-completion intervals, as well as for modifications to the trajectory of the production well, injection well, or both.

As will be recognized, for a reservoir of uniform quality, the rate at which it is depleted is predicted to be inversely proportional to the square root of the thickness of the pay above the depth of the producer wellbore. Thus, regions along a well pair trajectory that are thinner can negatively affect ultimate recovery by depleting faster. Once depleted, the thinner portion of the reservoir will contribute to continued heat losses, but will not contribute additional oil production.

Further, the thinner portions of the reservoir may become locations for steam coning into the production well. As less fluid is flowing into the production well at this location than at other areas along the production well, the chamber can expand downwards to the depth of the production well. When this occurs, either steam will enter the production well or production rates for the entire well will be need to be constrained, resulting in mobilized fluids accumulating above the producer in the more productive regions along the production well trajectory. This accumulation of fluid will reduce the effective steam chamber height and reduce recovery at these portions of the liner. Additionally, as steam injection is provided by a substantially constant pressure line source, the reduced steam demand in the areas of the reservoir with reduced pay thickness will result in a localized increase in chamber pressure near the wells which will further aggravate the coning tendency at these thinner pay locations.

As described herein, when a region that is expected to be depleted faster than the remainder of the well trajectory is located along a planned trajectory of a well pair, a number of strategies can be implemented to lower the chances that it will detrimentally affect overall performance. For example, there may be no open completions, in the production well, the injection well, or both, along that portion of the reservoir, as discussed with respect to FIG. 8.

By including no completions in a region, the recovery of the oil in the region will occur as the depleted zone spreads laterally along the well pair, and flows to other regions where the production well has completions. In situations where steam, or another heated fluid, is an injectant, growth of depletion into the uncompleted regions will benefit from the heat losses from the existing injection wells and production wells, which can create “hot fingers” in this direction, thereby accelerating the mobilization and drainage of oil.

When a region that is expected to be depleted faster than the remainder of the well spacing is located at the end of the planned trajectory of the well pair, as discussed with respect to FIG. 7, an additional opportunity is available to improve the cost effectiveness of the recovery process. Specifically, the injection well of the well pair can be drilled longer than the production well, creating a mismatch in their lengths.

When steam, or another heated fluid, is an injectant, having the injection well extend past the toe of the production well creates a “hot finger” in this direction. The hot finger accelerates the mobilization of the oil. Depending on the circumstances, the access to this additional resource may occur at different speeds. A change in speed of production can be accomplished by manipulating the injector well profile and/or the placement of the tubing string within the injector liner. For example, the fastest heating will occur when steam can access the entire length of the injection liner from the start of injection. This can be accomplished by installing an injection string to the end of the liner, or drilling the injection well extension with a shallow upward angle, as discussed with respect to FIG. 7(A). The shallow upward angle allows steam to rise in the extension and the condensed steam, or condensate, to drain freely out of the extension. Without this upward angle the removal of the heated oil will progress much slower as the gravity head is reduced.

Accordingly, by placing downward dips in the otherwise shallow upwards angle profile of the injector extension, as discussed with respect to FIG. 7(B), the distance of heating in the extension can be regulated. Specifically, the portion of the injection well that lies beyond the dips will not drain of condensate until after the depletion zone has extended beyond the first screen location on the other side of the dip. When the injectant is a non-heated solvent, having the injection well extend past the toe of the production well creates a pathway to accelerate the mixing of the solvent and oil in this direction. Thus, similar strategies for the injector extension discussed above can be applied with the non-heated solvent.

In some embodiments, the production well may extend past the injection well. In this the hydrocarbons entering the production liner may be redirected to the toe before being produced. Further, this can provide the ability to inject the injectant near the toe of the production well, for example, using a coiled tubing string. Once the well trajectories are designed, the liners may be designed and completions may be located.

At block 906, the production liners of the serpentine well pairs are designed. The designs are based in part on a number of considerations, including the expected well completions, the start-up techniques to be used, and the production strategies to be used, including artificial lift design and the desired number and location of the production points. Other considerations include strategies planned for transitioning to a follow-up recovery technology and preparing for the final shutdown of the pattern of wells. The design of the serpentine well pairs and patterns of wells can be modified in light of the liner design, resulting in an iterative process.

The design of the liners is based on the subsurface drainage boxes. Once the locations of the subsurface drainage boxes are known, an assessment is completed on the wellbore trajectories to ensure that the path can be successfully drilled and the liner installed.

To improve the ease at which the liners can be placed in the drilled hole, the diameter of the liner can be reduced one or more times towards the toe, as discussed with respect to FIG. 3. The size reduction makes the liner lighter and more flexible, allowing it to more easily conform to changes in direction of the drilled hole. Further, the size reduction may allow the toe of the liner to ride over top of small accumulations of materials in the drilled hole as it is pushed into the hole, lowering the chances of materials piling up in front of the liner. The reduction in liner cross-section will generally not interfere with the recovery performance due to the reduced total fluid rates expected in both the injection and production liners at these points.

The portions of the trajectories of the serpentine well pairs that have no openings can either be completed with blank pipe or have the completions obstructed to prevent in-flow. For example, one such obstruction that can be used is a scab liner that is set inside a production liner.

At block 908, the serpentine well pairs are drilled using the paths and well patterns selected. Where sufficient geologic contrast is present, for example, between an oil sand layer and a lower impermeable rock layer, the serpentine well pairs can be geosteered. The geosteering may be done by gamma ray detectors, seismic detectors, or any other suitable techniques. The geosteering may help to ensure that the actual well paths remains close to the base of the reservoir and in a region that has adequate vertical permeability. This may allow the development of acceptable production rates with the gravity drainage mechanism at the new well. As a result, the trajectory of the serpentine wells may undulate vertically and laterally as they pass through the reservoir interval.

At block 910, the liners are installed in the production wells and injection wells. During installation, liner completions, e.g., perforations, may be blocked so that the apparent weight of the liner can be manipulated by the amount of liquid and gas fill inside the liner, thereby making it easier to install. For example, the liner completions can be blocked using wax plugs. After installation, the wax is removed by melting, such as by using steam circulation during start-up.

At block 912, hydrocarbons are produced from the subsurface drainage boxes. During the production, process design and control combined with the selective obstruction of portions of the liner of the production wells can be used to prevent excess reproduction of an injected mobilizing fluid. Further, production rates may be controlled to help minimize the co-production of the injectant used to mobilize the hydrocarbon.

Depending on whether the injectant is steam, a steam-gas mixture, a steam-solvent mixture, solvent or gas, such procedures for controlling the amount of injectant co-production can include monitoring the bottom hole temperature or pressure, as well as the production rates of injectant observed at surface. In addition, the injectant amount and type may also be modified to keep the measurements within control ranges. The control measures can be modified to reflect changes in the injectant type and composition that may occur over the life of the project. In addition, the production liner or a production tubing string present within the liner could be completed with inflow control devices to restrict the production of injectant vapor. In some embodiments, each subsurface production box can be depleted in sequence, with the perforations, screens, or slots along the remaining portions of the trajectory of the production liner obstructed to prevent flow.

While the present techniques may be susceptible to various modifications and alternative forms, the embodiments discussed above have been shown only by way of example. However, it should again be understood that the techniques is not intended to be limited to the particular embodiments disclosed herein. Indeed, the present techniques include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.

Embodiments

An embodiment described herein provides a method for improving recovery from a subsurface hydrocarbon reservoir. The method includes mapping a base of a reservoir to determine a region that holds hydrocarbons and accessing the region by a serpentine well pair. The serpentine well pair includes a production well at a first elevation and an injection well at a higher elevation, and the production well is drilled with a variable trajectory to follow at least a portion of the base of the reservoir. At least a portion of the production well includes a liner with no perforations.

The method includes designing the serpentine well pair with a vertical placement, lateral placement, or both, that changes to allow the production well to intercept the region near a base within the reservoir. The production well may be drilled through intervals of non-pay to couple two or more pay intervals of pay. Portions of the production well may be completed in pay intervals with slotted pipe, wirewrap screen assemblies, or mesh rite screen assemblies.

A portion of the injection well may be drilled beyond the production well and an injector liner extension can be installed in the portion of the injection well that extends beyond the production well. The injector liner extension can be completed with slotted pipe, wirewrap screen assemblies, or mesh rite screen assemblies. At least a portion of the injection well that extends beyond the production well can be drilled at an angle to horizontal.

A portion of the production well may be drilled beyond the injection well and a production liner extension can be installed in the portion of the production well that extends beyond the injection well. The portion of the production well that extends beyond the injection well can be drilled at an angle to horizontal. The production liner extension can be completed with slotted pipe, wirewrap screen assemblies, or mesh rite screen assemblies.

The production well can extend through intervals of non-pay to couple two or more pay intervals in the reservoir. Portions of the production well can be completed with slotted pipe, wirewrap screen assemblies, or mesh rite screen assemblies. Portions of the production well can be completed with blank pipe.

A portion of the injection well can extend beyond the production well to form an injector liner extension. At least a portion of the injector liner extension can be completed with slotted pipe, wirewrap screen assemblies, or mesh rite screen assemblies. The injector liner extension can include blank pipe.

A portion of the production well can extend beyond the injection well to form a production liner extension. Any portion of the production liner that extends above a target depth for a liquid sump can be completed with blank pipe.

Another embodiment provides a method for drilling a well in a reservoir. The method includes planning a well trajectory for a serpentine well pair. The production well is drilled using lateral displacements and vertical displacements to follow a base of a pay interval in the reservoir. The production well is completed with a liner that includes perforations in regions comprising a hydrocarbon, wherein at least a portion of the production well has no perforations.

The method can include identifying well trajectories of the production well that need to be blocked to lower a production of an injected mobilizing fluid.

HARVESTING RESOURCE FROM VARIABLE PAY INTERVALS

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CPC

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