ENHANCING THE START-UP OF RESOURCE RECOVERY PROCESSES

Abstract

A method and systems are provided for the enhancement of a start-up of a resource recovery process. The system includes a well pair including a production well at a first elevation and an injection well at a higher elevation. The well pair is configured to force an initial fluid communication between the production well and the injection well to occur at a selected region along a completion of the production well and a completion of the injection well.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of Canadian patent application number 2,766,838 filed on Feb. 6, 2012 entitled ENHANCING THE START-UP OF RESOURCE RECOVERY PROCESSES, the entirety of which is incorporated 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 resources 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 dependent 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 hydrocarbons 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, to 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 well-based recovery techniques. 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.

For example, CSS techniques include a number of enhanced recovery methods for harvesting heavy oil from formations that use steam heat to lower the viscosity of the heavy oil. These steam assisted hydrocarbon recovery methods are described in U.S. Pat. No. 3,292,702 to Boberg, and U.S. Pat. No. 3,739,852 to Woods, et al., among others. CSS and other steam flood techniques have been utilized worldwide, beginning in about 1956 with the utilization of CSS in the Mene Grande field in Venezuela and steam flood in the early 1960s in the Kern River field in California.

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 often 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 be used in combination with steam in CSS processes, such as in mixtures with the steam or in alternate injections between steam injections. These techniques are described in U.S. Pat. No. 4,280,559 to Best, U.S. Pat. No. 4,519,454 to McMillen, and U.S. Pat. No. 4,697,642 to Vogel, among others.

Cyclic enhanced recovery techniques have been developed that are not based on thermal methods. For example, U.S. Pat. No. 6,769,486 to Lim, et al., discloses a cyclic solvent process for heavy oil production. In the process, a viscosity reducing hydrocarbon solvent is injected into a reservoir at a pressure sufficient to keep the hydrocarbon solvent in a liquid phase. The injection pressure may also be sufficient to cause dilation of the formation. The hydrocarbon solvent is allowed to mix with the heavy oil at the 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.

Canadian Regulatory Application No. 1,007,634, which was filed with Alberta's Energy Resources Conservation Board (ERCB) in April 1997, discusses previous laboratory and field pilot data using xylene as a solvent. In these cyclic solvent tests, the solvent was injected as a liquid and reproduced as a liquid. Xylene was selected for use in these previous tests because it had demonstrated full miscibility with Cold Lake heavy oil at all mixture concentrations.

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. Various embodiments of the SAGD process are described in Canadian Patent No. 1,304,287 to Edmunds and U.S. Pat. No. 4,344,485.

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 drainage 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. For example, U.S. Pat. No. 6,230,814 to Nasr, et al., teaches how the SAGD process can be further enhanced through the addition of small amounts of solvent to the injected steam. In addition, Butler, et al., “A New Process (Vapex) for Recovering Heavy Oils,” JCPT, Vol. 30, No. 1, 97-106, January-February 1991, teaches how solvent can be used instead of steam in a gravity drainage based recovery process to recover heavy oil from a subterranean reservoir.

A number of developments have focused on using solvents to lower the temperature of the extraction process. For example, Canadian Patent No. 2,243,105, to Mokrys, discloses a non-thermal vapor extraction method for the recovery of hydrocarbons from deep, high-pressure hydrocarbon reservoirs. The reservoirs may have been previously exploited by cold flow or may be virgin deposits. The target reservoirs are underlain by active aquifers. A mixture of a light hydrocarbon vapor solvent, such as ethane, propane, and butane, with reservoir natural gas is adjusted so that the dew point of the light hydrocarbon solvent matches the temperature and pressure conditions in the reservoir. The produced gas is analyzed for the solvent component, and enriched with the required amount of recycled solvent to match the dew point. The gas is then reintroduced into the reservoir as an injection gas. Both the recovered solvent and free gas are continuously circulated through the reservoir. The extraction can be accomplished by employing pairs of parallel horizontal injection/production wells, in a similar fashion to SAGD.

Similarly, Canadian Patent No. 2,494,391 and Canadian Patent Application Publication No. 2,584,712 by Chung, et al., disclose a cold solvent-based extraction method for extracting heavy oil from a reservoir. The method involves forming a solvent fluid chamber by solvent fluid injection and heavy oil production using combinations of horizontal and/or vertical injection wells. The combination may increase the recovery of heavy oil contained in a reservoir.

Solvents may also be used in concert with steam addition to increase the efficiency of the steam in removing the heavy oils. U.S. Pat. No. 6,230,814 to Nasr, et al., discloses a method for enhancing heavy oil mobility using a steam additive. The method included injecting steam and an additive into the formation. The additive includes a non-aqueous fluid, selected so that the evaporation temperature of the non-aqueous fluid is within about ±150° C. of the steam temperature at the operating pressure. Suitable additives include C₁ to C₂₅ hydrocarbons. At least a portion of the additive condenses in the formation. The mobility of the heavy oil obtained with the steam and solvent combination is greater than that obtained using steam alone under substantially similar formation conditions.

In the case of recovery processes, such as SAGD, that include an injection and a production well drilled in close proximity to one another, a number of techniques have been described for the establishment of communication between the injection well and the production well. For example, Canadian Patent No. 1,304,287 to Edmunds, et al., teaches that, when two wells are in close proximity, e.g., 10-25 feet (or 3-8 meters) apart, in a bitumen bearing reservoir, circulation of steam in both wellbores will heat the intervening reservoir sufficiently to allow the establishment of fluid communication between the injection and production wells.

In addition, Canadian Patent No. 2,241,478 to Chhina teaches that, when sufficient transmissibility exists in a reservoir, heated fluids can be continuously injected via the injection well and continuously produced via the production well. This may result in a degree of heating in the intervening reservoir that is sufficient to allow for the establishment of fluid communication between the injection well and the production well.

A paper by Kisman, et al., entitled “Numerical Simulation of the SAGD Process in the Burnt Lake Oil Sands Lease”, which was presented at the 1995 SPE International Heavy Oil Symposium in Calgary, Alberta, Canada, in June of 1995, teaches how cyclically injecting steam at sub-fracture pressures and producing fluids can be used to heat and partially deplete an intervening reservoir. The heating of the intervening reservoir may be sufficient to allow for the establishment of fluid communication between the injection well and the production well.

A paper by Donnelly entitled “Hilda Lake a Gravity Drainage Success”, which was presented at the 1999 SPE International Thermal Operations and Heavy Oil Symposium in Bakersfield, Calif. in March of 1999, teaches how solvent injection at sub-fracture pressures can be used to reduce the viscosity of oil in an intervening reservoir. The reduction of the viscosity of the oil may be sufficient to allow for direct steam injection at sub-fracture pressures, which may result in the establishment of fluid communication between the injection well and the production well.

Canadian Patent Application Publication No. 2,698,898 by Pugh, et al., teaches the injection of a solvent into one or both of an injection well and a production well at pressures too low to either compress the initial fluids present in the reservoir or dilate the pores of the reservoir rock. The injection of the solvent can be used to establish fluid communication between the injection well and the production well. However, according to this technique, the solvent must be injected at a pressure no higher than the initial reservoir pressure. Thus, no solvent would be able to enter the reservoir.

The recovery techniques discussed above may leave a substantial remainder of hydrocarbons in the reservoir. Further, the start-up processes for such techniques may be slow and unpredictable. For example, it may be difficult to predict the location of initial fluid communication between two wells in a well pair, as well as the amount of time it may take to establish the initial fluid communication between the two wells.

SUMMARY

An embodiment of the present techniques provides a system for the enhancement of a start-up of a resource recovery process. The system includes a well pair including a production well at a first elevation and an injection well at a higher elevation. The well pair is configured to force an initial fluid communication between the production well and the injection well to occur at a selected region along a completion of the production well and a completion of the injection well.

Another embodiment provides a method for the enhancement of a start-up of a resource recovery process. The method includes drilling a well pair through a reservoir, wherein the well pair includes a production well at a first elevation and an injection well at a higher elevation. The method also includes establishing fluid communication between the production well and the injection well by forcing an initial fluid communication to occur at a selected region along a well completion.

Another embodiment provides a system for harvesting resources from a reservoir. The system includes a reservoir including hydrocarbons and a well pair, wherein the well pair includes a production well and an injection well. The well pair is configured to establish fluid communication between the production well and the injection well by forcing an initial fluid communication to occur at one or more selected regions along a completion of the production well or a completion of the injection well, or any combination thereof. The well pair is also configured to enable a recovery of resources through a gravity drainage based recovery process once fluid communication has been established.

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 used for accessing hydrocarbon resources in a reservoir;

FIG. 2A is a schematic of a system for establishing fluid communication between a production well and an injection well;

FIG. 2B is a schematic of another system for establishing fluid communication between a production well and an injection well;

FIG. 3A is a schematic of a system for establishing an initial fluid communication between a production well and an injection well through the use of a selective, temporary obstruction covering a number of openings along a liner of the production well;

FIG. 3B is a schematic of a system for establishing the initial fluid communication between the production well and the injection well through the use of a selective, temporary obstruction covering a number of openings along the liner of the injection well;

FIG. 3C is a schematic of a system for establishing the initial fluid communication between the production well and the injection well through the use of the selective, temporary obstructions and on the liners and of both the production well and the injection well;

FIG. 4A is a schematic of a system for establishing an initial fluid communication between a production well and an injection well through a modification of a separation between the production well and the injection well at a selected region;

FIG. 4B is a schematic of a system for establishing a location for the initial fluid communication between the production well and the injection well by causing the injection well to approach the production well at the selected region;

FIG. 4C is a schematic of a system for establishing the initial fluid communication between the production well and the injection well by having the production well approach the injection well at a location;

FIG. 5 is a schematic of a system for establishing an initial fluid communication between a production well and an injection well through the selective injection of a solvent;

FIG. 6 is a schematic of a system for establishing an initial fluid communication between a production well and an injection well through the injection of a solvent into the production well and the injection of steam into the injection well;

FIG. 7A is a schematic of a system for establishing an initial fluid communication between a production well and an injection well through the use of a steam circulation process within the injection well;

FIG. 7B is a schematic of a system for establishing an initial fluid communication between the production well and the injection well through the use of a solvent injection process within the injection well;

FIG. 7C is a schematic of a system for establishing an initial fluid communication between the production well and the injection well through the use of a solvent injection process within both the production well and the injection well;

FIG. 8 is a schematic of a system for establishing complete fluid communication between a production well and an injection well after the initial fluid communication has been established at a selected region;

FIG. 9 is a top view of a well pair with horizontal variations in wellbore separation; and

FIG. 10 shows a process flow diagram of a method for enhancing the start-up of a resource recovery process.

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. It is often 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, can 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, “condensate” includes liquid water formed by the condensation of steam. Steam may also entrain liquid water, in the form of water droplets. This entrained water may also be termed condensate, as it may arise from condensation of the steam, although the entrained water droplets may also originate from the incomplete conversion of liquid water to steam in a boiler.

A “development” is a project for the recovery of hydrocarbons using integrated surface facilities and long term planning. The development can be directed to a single hydrocarbon reservoir, although multiple proximate reservoirs may be included.

As used herein, “exemplary” means “serving as an example, instance, or illustration.” Any embodiment described herein as “exemplary” is not to be construed as preferred or advantageous over other embodiments.

“Facility” as used in this description is a collection of physical equipment through which hydrocarbons and other fluids may be either produced from a reservoir or injected into a reservoir. A facility may also include 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, extraction plants, processing plants, water treatment 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 are used to refer to components found in bitumen, or other oil sands.

As discussed above, pore “dilation” refers to the enlargement of pores in rock or soil. The enlargement, or dilation, of such pores in rock or soil results in the rock or soil becoming more loosely packed.

As used herein, a “reservoir” is a subsurface rock or sand formation from which a production fluid 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 meters) to hundreds of feet (hundreds of meters).

The term “solvent” broadly refers to a substance or material capable at least in part of dissolving or dispersing one or more other materials or substances, such as to provide or form a solution. More specifically, as used herein, a solution is a compound that dissolves into and thus, reduces the viscosity of, naturally occurring hydrocarbons.

As discussed above, “steam assisted gravity drainage” (SAGD) is a thermal recovery process in which steam 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 usually 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 be based on heated water, wet steam, or dry steam, alone, or in any combinations. Further, any of these components may be combined with solvents to enhance the recovery. Such processes may include subsurface processes, such as cyclic steam stimulation (CSS), steamflooding, and SAGD, among others, and processes that use surface processing for the recovery, such as sub-surface mining and surface mining.

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-sectional shape, such as an oval, a square, a rectangle, a triangle, or other regular or irregular shapes. As used herein, the term “well,” when referring to an opening in the formation, may be used interchangeably with the term “wellbore.”

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.

OVERVIEW

Embodiments described herein provide a method and systems for enhancing the start-up of gravity drainage based recovery processes. Such a method and systems may be used to accelerate the start-up, provide for more predictable start-up locations, and reduce the costs for liner, tubular, or production fluid lift for gravity drainage based recovery processes.

According to current start-up strategies, the specific location along the liners where fluid communication between the production and injection wells will initially be established is often random and unpredictable. Factors that influence the specific location include the local proximity of the injection well and the production well, the local geologic variability, the effectiveness of the steam rates used during circulation to propagate heat along the length of the liner, and the effectiveness of the solvent in flowing through, and subsequently propagating away from, the liner. Thus, it is desirable to ensure that well designs and operating procedures are flexible enough to accommodate and react to such uncertainties. For example, if the initial fluid communication is established near the heels of the liner, i.e., the end of the liner adjacent to the intermediate casing string, it may be desirable to ensure that steam can be injected near the toe of the injection well liner, i.e., the end of the liner furthest from the intermediate casing string, to the keep the entire length of the interjection well hot. It may also be desirable to ensure that the remaining portions of the production well liner remain warm. This may be accomplished by forcing the fluids to travel to the toe of the production well liner before being produced from the well.

Embodiments disclosed herein provide a method and systems that cause the location of the initial fluid communication, i.e., the start-up location, to be more predictable. For example, in various embodiments, the separation between the injection well and the production well at the desired location, or locations, for initial fluid communication can be purposely reduced. In the case of a production well having a single pump located in the intermediate casing string just before the start, or heel, of the liner, the desired location for the establishment of initial fluid communication may be near the far end, or toe, of each of the liners. Such a location is used as the basis for the embodiments disclosed herein. However, it is to be understood that the discussion of the preferred start-up location as being near the toe of each of the liners is used merely for ease of discussion and is not intended to indicate that this location is to be used in every instance.

In various embodiments, a reduced separation between the injection well liner and the production well liner at each toe results in the faster conductive heating of the intervening reservoir at this location when the steam circulation approach is used for start-up. The reduced separation of the liners may also be combined with the injection of a viscosity reducing solvent, such as diesel, naphtha, or xylene, preferentially at the toes of the liners using, for example, small diameter coiled tubing string. This may result in a faster reduction of the viscosity of the oil present between the wells at this location. In addition, solvent injection may be performed independently of the reduction of the separation between the liners in order to increase the start-up rate, or to decrease the start-up costs.

In some embodiments, if the separation between the production well and the injection well is sufficiently small, steam circulation or solvent injection at a pressure higher than the initial reservoir pressure in one well may be adequate to establish thermal communication, or fluid communication, between the two wells in an acceptable period of time. Furthermore, thermal communication between the two wells may be established in an acceptable period of time by using steam circulation in one well and a targeted solvent injection in the other well.

The establishment of the initial fluid communication between the two wells at one or more desirable locations may allow the well design and associated surface facilities to be simplified and, thus, made less costly. For example, if fluid communication is established between the toes of the wells without having to circulate steam in the production well, the construction of steam injection tie-ins and steam metering for the production wells may be eliminated. Artificial lift systems that currently have maximum temperature constraints, such as electric submersible pumps (ESPs) and their associated electric cables, could be installed from the start of the operations. Steam could be injected via the injection well, communicate to the production well via the path established between the toes of the liners, and travel back along the production well liner to the pump location.

This unidirectional flow path allows the temperatures near the ESPs to be constrained by using conventional stream trap, or maximum temperature, control calculation procedures that are applied at the pump location. Energy efficiency of the steam injected during the start-up phase is significantly enhanced as counter-current flow of steam and condensate no longer occurs in either wellbore.

In addition, if fluid communication is established between the toe of each of the wells without having to circulate steam in the production well, the production well casing and liner sizes can be reduced, since a tubular for steam circulation may not be needed. The redirection of the production fluids to the toe of the production well prior to being produced as a means to ensure the entire production liner is heated prior to start-up may also be eliminated.

Furthermore, the associated production fluid testing scheme can be simplified. By including an artificial lift system from the start, the pressure of the fluids returning to the surface can be regulated to prevent the occurrence of a free gas (e.g., solution, in-situ generated steam, or solvent vapor) in the production stream. The volume and mass of the total production stream may be established using a mass meter, and the fraction of hydrocarbon and condensed injectant can be calculated by understanding the individual temperature-density relationships of the two components. This measurement approach can be applied where sufficient density difference naturally exists between the two components.

Where sufficient density difference does not exist at the current production temperature, due to the different thermal expansion rates, it can be created by selectively heating or cooling the entire production stream, or a representative slip stream thereof. If more than one injectant is present, such as when both steam and a volatile solvent are used, identification of the quantities of the three components can be estimated by adding small to moderate pressure reduction downstream of the mass meter and measuring the resulting volume, temperature, and pressure of the liquid and vapor streams. Recombination calculations can then be used to estimate the volumes of the two non-aqueous components in the production stream.

In some embodiments, fluid communication is established between the toe of each of the injection and production wells without having to circulate steam in the injection well. In such cases, the steam injection capabilities for the injection well could be simplified. In addition, piping and measurement facilities for the production of fluids from the injection well may be eliminated. Further, the wellhead design can be simplified, and the well casing and liner sizes can be reduced as two tubing strings for steam injection and fluid returns during the start-up phase may no longer be included.

Alternatively, to create the desired location of initial fluid communication between the injection well and the production well, it is possible to obstruct the liner openings in all but the desired location in one, or both, of the liners. For example, a “throttled flow” liner with the desired screened sections left open in one or both wells may be combined with the option of solvent injection for establishing the initial fluid communication in order to further simplify the well design. The toe tubing string may no longer be used to place the solvent at the desired location. Once the desired communication is established, some or all of the remaining entry points in the liners can be unblocked.

Using one or more of the strategies of the current invention, initial communication between the injection well and the production well at the desirable location may result. This outcome creates additional opportunities for further optimization of the SAGD well design and, in some cases, enables an accelerated start of SAGD operations and oil production. Although embodiments disclosed herein are described in the context of the SAGD recovery process, it can be understood that they are equally applicable to all thermal, thermal-solvent, and solvent based recovery processes where gravity drainage is, or eventually becomes, the dominant recovery mechanism. Embodiments disclosed herein relate to a method and systems for optimizing the depletion of a hydrocarbon resource when using thermal, thermal-solvent, and solvent based recovery processes, as well as a series of well designs and operating procedures that allow this strategy to be successfully implemented.

SAGD Process

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. The injection wells 106 may be horizontally drilled through the reservoir 102. Production wells 108 may be drilled horizontally through the reservoir 102. Generally, a production well 108 may be drilled under each injection well 106, but this is not required in all embodiments. The injection wells 106 and the production wells 108 can 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.

Each production well 108 and corresponding injection well 106 forms a well pair 124. The production wells 108 and injection wells 106 may have a segment that is substantially horizontal and, in some circumstances, has a slight upward slope from the heel 126, at which the well branches to the surface 112, to the toe 128, at which the well ends. Each production well 108 may be designed such that it follows the trajectory of the corresponding injection well 106 along a base 130 of the reservoir.

In various embodiments described herein, each well pair 124 may be modified in any of a number of ways to allow for the establishment of the initial fluid communication between the production well 108 and the injection well 106 at a selected location, or region. For example, the vertical distance between the injection well 106 and the production well 108 may be modified at a selected region 132 in order to increase the likelihood that the initial fluid communication will occur at the selected region 132. The wells 106 and 108 may have variations in the horizontal plane that cause increased or decreased separation between the wells 106 and 108. Further, certain regions of a completion 134 of the injection well 106 and a completion 136 of the production well 108 may be obstructed, with a desired region 138 for the initial fluid communication remaining unobstructed. This may allow the initial fluid communication to occur at the desired region 138. Any number of other configurations or techniques may be used as discussed with respect to FIGS. 2-10.

Establishing Fluid Communication Between a Production Well and an Injection Well

FIG. 2A is a schematic of a system 200 for establishing fluid communication between a production well 202 and an injection well 204. Steam 206 may be circulated to a toe 208 of both the production well 202 and the injection well 204 using a toe tubing string 210. A combination 212 of steam and water may then be circulated from the toe 208 of both the production well 202 and the injection well 204 back towards a heel (not shown) of each of the wells 202 and 204. An intervening area of a reservoir 214 located between the production well 202 and the injection well 204 may be heated through a combination of heat conduction and fluid leak-off, e.g., convection. A completion of each well, such as a production liner 218 of the production well 202 and an injection liner 220 of the injection well 204 may also be perforated in order to allow for the establishment of fluid communication between the two wells 202 and 204, as indicated by the arrows 216.

FIG. 2B is a schematic of another system 222 for establishing fluid communication between a production well 224 and an injection well 226. Solvent 228 may be injected into the production well 224 and the injection well 226. The solvent 228 may aid in the establishment of fluid communication between the production well 224 and the injection well 226 by causing fluid to flow from the production well 224 to the injection well 226 through an intervening area of a reservoir 230, as indicated by the arrows 232. A production liner 234 of the production well 224 and an injection liner 236 of the injection well 226 may also be perforated in order to allow for the establishment of fluid communication between the two wells 224 and 226.

In contrast to the system 200, the system 222 may not have a toe tubing string, especially if the fluids contained in the wells 224 and 226 are displaced by the solvent 228 during the completion phase. Because the solvent 228 leaves the production well 224 and the injection well 226 during the injection process, the pressure within the two wells 224 and 226 must be forced to exceed the initial formation pressure. In most circumstances, such pressure can be achieved by using the pressure head of the solvent 228 present inside the intermediate casing string, and by adding solvent as needed to maintain the pressure head using either a continuous feed system or an intermediate feed system. In some circumstances it may be beneficial to maintain a pressurized gas head above the solvent column to ensure that the desired solvent pressure is maintained.

While the systems 200 and 222 provide for the establishment of fluid communication between a production well and an injection well, the location of the initial fluid communication is uncertain with these approaches. Thus, it may be difficult to predict or control the start-up of the hydrocarbon recovery process. It is often desirable to achieve a faster start-up of the hydrocarbon recovery process with a more predictable start-up location, e.g., location of initial fluid communication between the two wells.

Establishing Fluid Communication at a Selected Region

FIG. 3A is a schematic of a system 300 for establishing an initial fluid communication between a production well 302 and an injection well 304 through the use of a selective, temporary obstruction 306 covering a number of openings along a liner 308 of the production well 302. Toe tubing strings 310 may also be used within each of the wells 302 and 304 in accordance with a steam circulation startup technique to ensure that the location of the initial fluid communication between the production well 302 and the injection well 304 is established at a selected region 312, as indicated by the arrow 314. For example, in some embodiments, the selected region 312 may be between the toe of each of the liners 308 and 316 of the production well 302 and the injection well 304, respectively. In various embodiments, the selective, temporary obstruction 306 covering portions of the liner 308 of the production well 302 may prevent the initial fluid communication from occurring anywhere other than the selected region 312. For example, as shown in FIG. 3A, the selected region 312 may be the only location along the liner 308 of the production well 302 that is not blocked, or obstructed, from communicating with the surrounding environment.

FIG. 3B is a schematic of a system 318 for establishing the initial fluid communication between the production well 302 and the injection well 304 through the use of a selective, temporary obstruction 320 covering a number of openings along the liner 316 of the injection well 304. In various embodiments, the selective, temporary obstruction 320 on the liner 316 of the injection well 304 may prevent the initial fluid communication from occurring anywhere other than the selected region 312. For example, as shown in FIG. 3B, the selected region 312 may be the only location along the liner 316 of the injection well 304 that is not blocked, or obstructed, from communicating with the surrounding environment.

FIG. 3C is a schematic of a system 322 for establishing the initial fluid communication between the production well 302 and the injection well 304 through the use of the selective, temporary obstructions 306 and 320 on the liners 308 and 316 of both the production well 302 and the injection well 304. In various embodiments, the selective, temporary obstructions 306 and 320 on the liners 308 and 316 of the two wells 302 and 304 may prevent the initial fluid communication from occurring anywhere other than the selected region 312. For example, as shown in FIG. 3C, the selected region 312 may be the only location along the liners 308 and 316 of the production well 302 and the injection well 304, respectively, that is not blocked, or obstructed, from communicating with the surrounding environment.

According to the systems 300, 318, and 322, the selective, temporary obstructions 306 and 320 may be removed once the initial fluid communication between the production well 302 and the injection well 304 has been established. The selective, temporary obstructions 306 and 320 may include, for example, scab liners or shear plugs that are to be physically removed, acidizable plugs that are to be chemically removed, a wax coating on the liner that is to be removed by heating, or a material than can be melted or dissolved by steam or water. In addition, the selective, temporary obstructions 306 and 320 may be provided by the presence of an alternate fluid type in the wellbore, as discussed further with respect to FIG. 5.

Once the selective, temporary obstructions 306 and 320 are removed, secondary locations of fluid communication between the production well 302 and the injection well 304 may be rapidly established. In some embodiments, the portions of the liners 308 and 316 of the production well 302 and the injection well 304, respectively, that are covered by the selective, temporary obstructions 306 and 320 may be continuously heated in order to aid in the establishment of the secondary locations of fluid communication after the selective, temporary obstructions 306 and 320 are removed.

FIG. 4A is a schematic of a system 400 for establishing an initial fluid communication between a production well 402 and an injection well 404 through a modification of a separation between the production well 402 and the injection well 404 at a selected region 406. Toe tubing strings 408 may also be used within each of the wells 402 and 404 in accordance with a steam circulation startup technique to ensure that the location of the initial fluid communication between the production well 402 and the injection well 404 is established at the selected region 406, as indicated by the arrow 410.

In various embodiments, a vertical separation or a lateral separation, or both, between the production well 402 and the injection well 404 may be selectively adjusted according to the specific application. The separation may be adjusted such that the initial fluid communication between the production well 402 and the injection well 404 is more likely to occur at the selected region 406. For example, as shown in FIG. 4A, the selected region 406 may be at the toe of each of the liners of the production well 402 and the injection well 404, and a distance of the injection well 404 from the production well 402 may be modified in the selected region 406 to increase the likelihood that the initial fluid communication between the two wells 402 and 404 will occur near the toes. Further, in various embodiments, a separation between the production well 402 and the injection well 404 may be modified in several selected regions in order to allow for an fluid communication to develop between the two wells 402 and 404 at each of the selected regions.

FIG. 4B is a schematic of a system 412 for establishing a location for the initial fluid communication between the production well 402 and the injection well 404 by causing the injection well 404 to approach the production well 402 at the selected region 406. The system 412 may also include selective, temporary obstructions along the liners of one or both of the wells 402 and 404. Such obstructions may aid in the establishment of the initial fluid communication at the selected region 406. For example, as shown in FIG. 4B, the system 412 may include a selective, temporary obstruction 414 along a liner 416 of the production well 402.

FIG. 4C is a schematic of a system 418 for establishing the initial fluid communication between the production well 402 and the injection well 404 by having the production well 402 approach the injection well 404 at a location 420. The modification of the separation between the production well 402 and the injection well 404 at the location 420 may cause the initial fluid communication between the two wells 402 and 404 to be established at a selected region 422. For example, the selected region 422 may be a specific location along the liner 416 of the production well 402. The modification of the separation between the production well 402 and the injection well 404 at the location 420 may cause fluid to flow from the location 420 to the selected region 422 through an intervening region of a reservoir 424, as indicated by the arrow 426. Further, in some embodiments, a selective, temporary obstruction 428 along the liner 416 of the production well 402 in the location 420 may prevent the initial fluid communication from occurring at the location 420. Conductive heating along the outside of the liner 416 of the production well 402 will allow fluid flow from the location 420 to the selected region 422. In this case, the obstruction may be permanent to block the formation of a direct steam path between the injection well 404 and the production well 402.

FIG. 5 is a schematic of a system 500 for establishing an initial fluid communication between a production well 502 and an injection well 504 through the selective injection of a solvent 506. A toe tubing string 508 may be used in each of the two wells 502 and 504 to selectively inject the solvent 506 into a liner 510 of the production well 502 and a liner 512 of the injection well 504. In some embodiments, backflow of the solvent 506 along one or both of the liners 510 and 512 is impeded though the maintenance of a water fill in the liner annulus, resulting in a solvent-water interface 513. Further, in various embodiments, the locations of the toe tubing strings 508 may be such that the injection of the solvent 506 causes the initial fluid communication between the production well 502 and the injection well 504 to occur at a selected region 514, as indicated by the arrow 516.

As more than a year can pass between the drilling of a well pair and the completion of the surface facilities that are used to allow steam injection and fluid production, this extended period of time can be used for the establishment of fluid communication using a solvent based start-up technique. As the length of the available time period increases, a lower injection pressure and solvent injection rate can be used, allowing for a better mixing of the solvent and oil in the near wellbore reservoir region. While this approach may seem to be a slower procedure, it does achieve the desired result of allowing the well pairs to go directly to normal SAGD operations once the required steam generation and fluids processing surface facilities are available.

FIG. 6 is a schematic of a system 600 for establishing an initial fluid communication between a production well 602 and an injection well 604 through the injection of a solvent 606 into the production well 602 and the injection of steam 608 into the injection well 604. For example, a steam circulation process may be utilized to inject the steam 608 into the injection well 604, while a solvent injection process may be utilized to inject the solvent 606 into the production well 602. In some embodiments, a toe tubing string 610 within the injection well 604 may be used to circulate the steam 608. In various embodiments, the simultaneous implementation of the steam circulation process and the solvent injection process may allow for the rapid establishment of the initial fluid communication between the production well 602 and the injection well 604 at a selected region 612, as indicated by the arrow 614. Further, in some embodiments, a selective, temporary obstruction 616 along a liner 618 of the injection well 604 helps to ensure that the initial fluid communication occurs at the selected region.

In some embodiments, the configuration of the system 600 may cause the production well 602 to remain relatively cool, allowing an artificial lift system that has a maximum temperature limitation to be installed as part of the initial completion process. This may reduce the overall cost of the completion process.

FIG. 7A is a schematic of a system 700 for establishing an initial fluid communication between a production well 702 and an injection well 704 through the use of a steam circulation process within the injection well 704. Steam 706 may be injected into the injection well 704 though a toe tubing string 708. A separation between the production well 702 and the injection well 704 at a selected region 710 may be adjusted such that the selected region 710 is the location with the minimum distance between the two wells 702 and 704. The steam circulation process combined with the modification of the separation between the two wells 702 and 704 at the selected region 710 may ensure that the initial fluid communication between the two wells 702 and 704 is established at the selected region 710, as indicated by the arrow 712. In various embodiments, the system 700 may reduce the overall cost of the completion process, since the production well 702 may be a simple wellbore without any modifications.

FIG. 7B is a schematic of a system 714 for establishing an initial fluid communication between the production well 702 and the injection well 704 through the use of a solvent injection process within the injection well 704. The solvent injection process may involve the injection of a solvent 716 into the injection well 704 in order to aid in the establishment of the initial fluid communication between the two wells 702 and 704. As described above with respect to FIG. 7A, a separation between the production well 702 and the injection well 704 at the selected region 710 may be adjusted such that the selected region 710 is the location with the minimum distance between the two wells 702 and 704. The solvent injection process combined with the modification of the separation between the two wells 702 and 704 at the selected region 710 may ensure that the initial fluid communication between the two wells 702 and 704 is established at the selected region 710, as indicated by the arrow 712. In various embodiments, the system 714 may also reduce the overall cost of the completion process, since both the injection well 704 and the production well 702 may be a simple wellbore without any modifications.

FIG. 7C is a schematic of a system 718 for establishing an initial fluid communication between the production well 702 and the injection well 704 through the use of a solvent injection process within both the production well 702 and the injection well 704. The solvent injection process may involve the injection of the solvent 716 into the production well 702 and the injection well 704 in order to aid in the establishment of the initial fluid communication between the two wells 702 and 704. As described above with respect to FIGS. 7A and 7B, a separation between the production well 702 and the injection well 704 at the selected region 710 may be adjusted such that the selected region 710 is the location with the minimum distance between the two wells 702 and 704. The solvent injection process within both of the wells 702 and 704 combined with the modification of the separation between the two wells 702 and 704 at the selected region 710 may ensure that the initial fluid communication between the two wells 702 and 704 is established at the selected region 710, as indicated by the arrow 712. In various embodiments, the system 718 may also reduce the overall cost of the completion process, since both the injection well 704 and the production well 702 may be a simple wellbore without any modifications.

FIG. 8 is a schematic of a system 800 for establishing complete fluid communication between a production well 802 and an injection well 804 after the initial fluid communication has been established at a selected region 806. In various embodiments, once the initial fluid communication has been established between the production well 802 and the injection well 804 at the selected region 806, as indicated by the arrow 808, the start-up of the SAGD process can continue with steam 810 being injected via the injection well 804, and steam and condensate 812 being returned via the production well 802. In some embodiments, a steam trap control is applied at the heel of the liner of the production well 802. Over time, complete, or nearly complete, fluid communication will be established between the production well 802 and the injection well 804.

While a toe tubing string is not shown in FIG. 8, alternate configurations could include a toe tubing string in the injection well 804 for the injection of the steam 810. For such configurations, the injection of the steam 810 may occur via the annular space, via the toe tubing string itself, or via both the annular space and the toe tubing string, depending on the specific application. In addition, the injection of the steam 810 may occur via a toe tubing string that has a blocked toe end and a series of small diameter openings along its length to distribute the steam 810 along the length of the injection well 804.

FIG. 9 is a top view of a well pair 900 with horizontal variations in wellbore separation. The well pair 900 may include a lower production well 902 and an upper injection well 904. The desired variation in the wellbore separation may be generated by changing the lateral separation between the lower production well 902 and the upper injection well 904. This may create one or more intervals 906 for the preferential establishment of initial fluid communication between the lower production well 902 and the upper injection well 904. In some embodiments, the one or more intervals for the preferential establishment of initial fluid communication may be established by manipulating both the lateral separation and the vertical separation between the lower production well 902 and the upper injection well 904.

Method for Enhancing the Start-Up of Resource Recovery Processes

FIG. 10 shows a process flow diagram of a method 1000 for enhancing the start-up of a resource recovery process. In some embodiments, the method 1000 may accelerate the start-up of the resource recovery process, and may also increase the predictability of the start-up location, i.e., the location of initial fluid communication, for the resource recovery process. The resource recovery process may be a thermal based gravity drainage process, a thermal-solvent based gravity drainage process, or a solvent based gravity drainage process, among others. In addition, the resource recovery process may be a gravity drainage based recovery process. In various embodiments, the resource to be recovered includes hydrocarbons.

The method 1000 begins at block 1002 with the drilling of a well pair through a reservoir. The well pair may include a production well at a first elevation and an injection well at a higher elevation. The trajectories of the production well and the injection well may be as closely aligned as possible in order to maintain an approximate degree of separation between the two wells.

At block 1004, fluid communication between the production well and the injection well may be established by forcing an initial fluid communication to occur at a selected region along the well completion. For example, the initial fluid communication may be forced to occur at a selected region along a liner of the production well or a liner of the injection well. The selected region may be a desired location for the initial fluid communication between the production well and the injection well. In various embodiments, the selected region is the toe of the liner of the production well or the injection well, or both. In addition, the well completion may be a completion of the production well or a completion of the injection well, or both.

In some embodiments, establishing the fluid communication between the two wells includes adjusting a separation between the production well and the injection well at the selected region. For example, a vertical separation or a lateral separation, or both, between the two wells may be adjusted. Furthermore, the separation between the production well and the injection well may be adjusted at several locations along the completion of the production well and the completion of the injection well in order to force the initial fluid communication to occur at several selected regions.

In some embodiments, establishing the fluid communication between the two wells includes selectively and temporarily obstructing one or more regions of a completion of the production well or the injection well, or both, in order to ensure that the initial fluid communication occurs at the selected region. For example, a liner of a production well may be obstructed everywhere except at the selected region, so that the initial fluid communication between the production well and an injection well may occur only at the selected region. In addition, in some embodiments, multiple selective, temporary obstructions are used to ensure that the initial fluid communication occurs at several selected regions.

Further, in some embodiments, establishing the fluid communication between the two wells includes selectively injecting a solvent or steam, or any combination thereof, into the production well or the injection well, or both, to provide for the establishment of the initial fluid communication at the selected region. For example, a toe tubing string within the production well or the injection well, or both, may be used to selectively inject the solvent or the steam into the production well or the injection well at the selected region. In various embodiment, the solvent is injected into the production well or the injection well using a solvent injection system, while the steam is injected into the production well or the injection well using a steam injection system. According to an exemplary configuration, the solvent is injected into the production well, and the steam is injected into the injection well, to accelerate the establishment of the initial fluid communication at the selected region.

FIG. 10 is not intended to indicate that all of the steps of the method 1000 are to be included in every case. Moreover, any number of additional steps may be included according to the specific application. For example, once the initial fluid communication between the production well and the injection well has been established at block 1004, additional fluid communication between the two wells may continue along both directions of the completion of the production well and the completion of the injection well starting from the region of the initial fluid communication. Once complete, or nearly complete, fluid communication has been established, resources may be recovered from the reservoir through a gravity drainage based recovery process. Furthermore, it is to be understood that, according to the method 1000, the initial fluid communication may not occur directly at a selected region but, rather, may occur in proximity to the selected region.

In some embodiments, the method 1000 does not result in the acceleration of the establishment of the fluid communication between the production well and the injection well. Rather, the method 1000 may actually slow down the timing of the initial fluid communication, but may still result in an acceleration of the conversion to normal SAGD operations. In addition, the method 1000 may not result in an appreciable change in timing but, instead, may allow for significant cost savings with respect to well and surface equipment design, for example.

The above-described embodiments of the invention are intended to be examples only. Alterations, modifications, and variations can be effected to the particular embodiments by those of ordinary skill in the art without departing from the scope of the invention, which is defined solely by the claims appended hereto.

Embodiments

Embodiments of the invention may include any combinations of the methods and systems shown in the following numbered paragraphs. This is not to be considered a complete listing of all possible embodiments, as any number of variations can be envisioned from the description above.

1. A system for enhancing a start-up of a resource recovery process, including a well pair including a production well at a first elevation and an injection well at a higher elevation, wherein the well pair is configured to force an initial fluid communication between the production well and the injection well to occur at a selected region along a completion of the production well and a completion of the injection well.

2. The system of paragraph 1, wherein the resource recovery process includes a thermal based gravity drainage process, a thermal-solvent based gravity drainage process, or a solvent based gravity drainage process.

3. The system of any of paragraphs 1 or 2, wherein the selected region includes a toe of a liner of the production well or a toe of a liner of the injection well, or both.

4. The system of any of paragraphs 1, 2, or 3, wherein the selected region includes a desired location for the initial fluid communication between the production well and the injection well.

5. The system of any of paragraphs 1-4, wherein a vertical separation or a lateral separation, or both, between the production well and the injection well is modified to force the initial fluid communication to occur at the selected region.

6. The system of paragraph 5, wherein the vertical separation or the lateral separation, or both, between the production well and the injection well is modified at several locations to force the initial fluid communication to occur at several selected regions.

7. The system of any of paragraphs 1-5, including a temporary obstruction along the completion of the production well or the completion of the injection well, wherein the temporary obstruction does not obstruct the selected region, and wherein the temporary obstruction forces the initial fluid communication to occur at the selected region.

8. The system of any of paragraphs 1-5 or 7, including a solvent injection system for selectively injecting a solvent into the production well or the injection well, or both, to force the initial fluid communication to occur at the selected region.

9. The system of any of paragraphs 1-5, 7, or 8, including a steam injection system for selectively injecting steam into the production well or the injection well, or both, to force the initial fluid communication to occur at the selected region.

10. A method for enhancing a start-up of a resource recovery process, including:

• • drilling a well pair through a reservoir, wherein the well pair includes a production well at a first elevation and an injection well at a higher elevation; and
  • establishing fluid communication between the production well and the injection well by forcing an initial fluid communication to occur at a selected region along a well completion.

11. The method of paragraph 10, wherein the selected region includes a toe of a liner of the production well or a toe of a liner of the injection well, or both.

12. The method of any of paragraphs 10 or 11, wherein the selected region includes a desired location for the initial fluid communication between the production well and the injection well.

13. The method of any of paragraphs 10, 11, or 12, wherein the well completion include a completion of the production well or a completion of the injection well, or any combination thereof.

14. The method of any of paragraphs 10-13, wherein establishing the initial fluid communication includes adjusting a separation between the production well and the injection well at the selected region.

15. The method of paragraph 14, including adjusting the separation between the production well and the injection well at several locations along a completion of the production well and a completion of the injection well to force the initial fluid communication to occur at several selected regions.

16. The method of paragraph 14, including adjusting a vertical separation or a lateral separation, or any combination thereof, between the production well and the injection well at the selected region.

17. The method of any of paragraphs 10-14, wherein establishing the initial fluid communication includes selectively and temporarily obstructing one or more regions of a completion of the production well or the injection well, or both, in order to ensure that the initial fluid communication occurs at the selected region.

18. The method of any of paragraphs 10-14 or 17, wherein establishing the initial fluid communication includes selectively injecting a solvent or steam, or any combination thereof, into the production well or the injection well, or both, to accelerate an establishment of the initial fluid communication at the selected region.

19. The method of paragraph 18, including inserting a toe tubing string into a liner of the production well or a liner of the injection well, or both, wherein the toe tubing string is used to selectively inject the solvent or the steam, or any combination thereof, into the production well or the injection well, or both, at the selected region.

20. The method of paragraph 18, including injecting the solvent into the production well and injecting the steam into the injection well to provide for an establishment of the initial fluid communication at the selected region.

21. The method of any of paragraphs 10-14, 17, or 18, wherein the resource recovery process includes a thermal, thermal-solvent, or solvent based recovery process.

22. The method of any of paragraphs 10-14, 17, 18, or 21, wherein the resource recovery process includes a gravity drainage based recovery process.

23. A system for harvesting resources from a reservoir, including:

• • a reservoir including hydrocarbons; and
  • a well pair, wherein the well pair includes a production well and an injection well, and wherein the well pair is configured to:
    • establish fluid communication between the production well and the injection well by forcing an initial fluid communication to occur at one or more selected regions along a completion of the production well or a completion of the injection well, or any combination thereof; and
    • enable a recovery of resources through a gravity drainage based recovery process once fluid communication has been established.

24. The system of paragraph 23, wherein a lateral separation or a vertical separation, or both, between the production well and the injection well is changed at the one or more selected regions to force the initial fluid communication to occur in proximity to the one or more selected regions.

25. The system of any of paragraphs 23 or 24, including a solvent injection system for selectively injecting a solvent into the production well or the injection well, or both, at the one or more selected regions to force the initial fluid communication to occur at the one or more selected regions.

26. The system of paragraph 25, wherein the solvent injection system includes a toe tubing string for selectively injecting the solvent at the one or more selected regions.

27. The system of any of paragraphs 23, 24, or 25, including a steam injection system for selectively injecting steam into the production well or the injection well, or both, at the one or more selected regions to force the initial fluid communication to occur at the one or more selected regions.

28. The system of any of paragraphs 23-25, or 27, including one or more temporary and selective obstructions within the completion of the production well and the completion of the injection well, wherein the one or more temporary and selective obstructions force the initial fluid communication to occur at the one or more selected regions.

29. The system of any of paragraphs 23-25, 27, or 28, wherein the resources include hydrocarbons.

30. The system of any of paragraphs 23-25 or 27-29, wherein the fluid communication between the production well and the injection well begins with the initial fluid communication at the one or more selected regions and continues along both directions of the completion of the production well and the completion of the injection well starting from the one or more selected regions.

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.

Claims

1. A system for enhancing a start-up of a resource recovery process, comprising a well pair comprising a production well at a first elevation and an injection well at a higher elevation, wherein the well pair is configured to force an initial fluid communication between the production well and the injection well to occur at a selected region along a completion of the production well and a completion of the injection well.

2. The system of claim 1, wherein the resource recovery process comprises a thermal based gravity drainage process, a thermal-solvent based gravity drainage process, or a solvent based gravity drainage process.

3. The system of claim 1, wherein the selected region comprises a toe of a liner of the production well or a toe of a liner of the injection well, or both.

4. The system of claim 1, wherein the selected region comprises a desired location for the initial fluid communication between the production well and the injection well.

5. The system of claim 1, wherein a vertical separation or a lateral separation, or both, between the production well and the injection well is modified to force the initial fluid communication to occur at the selected region.

6. The system of claim 5, wherein the vertical separation or the lateral separation, or both, between the production well and the injection well is modified at several locations to force the initial fluid communication to occur at several selected regions.

7. The system of claim 1, comprising a temporary obstruction along the completion of the production well or the completion of the injection well, wherein the temporary obstruction does not obstruct the selected region, and wherein the temporary obstruction forces the initial fluid communication to occur at the selected region.

8. The system of claim 1, comprising a solvent injection system for selectively injecting a solvent into the production well or the injection well, or both, to force the initial fluid communication to occur at the selected region.

9. The system of claim 1, comprising a steam injection system for selectively injecting steam into the production well or the injection well, or both, to force the initial fluid communication to occur at the selected region.

10. A method for enhancing a start-up of a resource recovery process, comprising:

drilling a well pair through a reservoir, wherein the well pair comprises a production well at a first elevation and an injection well at a higher elevation; and

establishing fluid communication between the production well and the injection well by forcing an initial fluid communication to occur at a selected region along a well completion.

11. The method of claim 10, wherein the selected region comprises a toe of a liner of the production well or a toe of a liner of the injection well, or both.

12. The method of claim 10, wherein the selected region comprises a desired location for the initial fluid communication between the production well and the injection well.

13. The method of claim 10, wherein the well completion comprise a completion of the production well or a completion of the injection well, or any combination thereof.

14. The method of claim 10, wherein establishing the initial fluid communication comprises adjusting a separation between the production well and the injection well at the selected region.

15. The method of claim 14, comprising adjusting the separation between the production well and the injection well at several locations along a completion of the production well and a completion of the injection well to force the initial fluid communication to occur at several selected regions.

16. The method of claim 14, comprising adjusting a vertical separation or a lateral separation, or any combination thereof, between the production well and the injection well at the selected region.

17. The method of claim 10, wherein establishing the initial fluid communication comprises selectively and temporarily obstructing one or more regions of a completion of the production well or the injection well, or both, in order to ensure that the initial fluid communication occurs at the selected region.

18. The method of claim 10, wherein establishing the initial fluid communication comprises selectively injecting a solvent or steam, or any combination thereof, into the production well or the injection well, or both, to accelerate an establishment of the initial fluid communication at the selected region.

19. The method of claim 18, comprising inserting a toe tubing string into a liner of the production well or a liner of the injection well, or both, wherein the toe tubing string is used to selectively inject the solvent or the steam, or any combination thereof, into the production well or the injection well, or both, at the selected region.

20. The method of claim 18, comprising injecting the solvent into the production well and injecting the steam into the injection well to provide for an establishment of the initial fluid communication at the selected region.

21. The method of claim 10, wherein the resource recovery process comprises a thermal, thermal-solvent, or solvent based recovery process.

22. The method of claim 10, wherein the resource recovery process comprises a gravity drainage based recovery process.

23. A system for harvesting resources from a reservoir, comprising:

a reservoir comprising hydrocarbons; and

a well pair, wherein the well pair comprises a production well and an injection well, and wherein the well pair is configured to: establish fluid communication between the production well and the injection well by forcing an initial fluid communication to occur at one or more selected regions along a completion of the production well or a completion of the injection well, or any combination thereof; and enable a recovery of resources through a gravity drainage based recovery process once fluid communication has been established.

24. The system of claim 23, wherein a lateral separation or a vertical separation, or both, between the production well and the injection well is changed at the one or more selected regions to force the initial fluid communication to occur in proximity to the one or more selected regions.

25. The system of claim 23, comprising a solvent injection system for selectively injecting a solvent into the production well or the injection well, or both, at the one or more selected regions to force the initial fluid communication to occur at the one or more selected regions.

26. The system of claim 25, wherein the solvent injection system comprises a toe tubing string for selectively injecting the solvent at the one or more selected regions.

27. The system of claim 23, comprising a steam injection system for selectively injecting steam into the production well or the injection well, or both, at the one or more selected regions to force the initial fluid communication to occur at the one or more selected regions.

28. The system of claim 23, comprising one or more temporary and selective obstructions within the completion of the production well and the completion of the injection well, wherein the one or more temporary and selective obstructions force the initial fluid communication to occur at the one or more selected regions.

29. The system of claim 23, wherein the resources comprise hydrocarbons.

30. The system of claim 23, wherein the fluid communication between the production well and the injection well begins with the initial fluid communication at the one or more selected regions and continues along both directions of the completion of the production well and the completion of the injection well starting from the one or more selected regions.