Recompaction of Sand Reservoirs

Abstract

Methods and systems for recompacting a hydrocarbon reservoir to prevent override of a fill material are provided. An exemplary method includes detecting a slurry override condition and reducing a pressure within the reservoir so as to reapply a stress from an overburden.

Description

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the priority benefit of U.S. Provisional Patent Application 61/500,456 filed 23 Jun. 2011 entitled RECOMPACTION OF SAND RESERVOIRS, the entirety of which is incorporated by reference herein.

FIELD

The present techniques are directed to recompacting sand reservoirs. More specifically, the recompaction may be used to mitigate sand override in such reservoirs.

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 hydrocarbons are dwindling, leaving less accessible sources to satisfy future energy needs. However, as the costs of hydrocarbons increase, these less accessible sources become economically attractive.

Recently, the harvesting of oil sands to remove bitumen has become more economical. Hydrocarbon removal from the oil sands may be performed by several techniques. For example, a well can be drilled to an oil sand reservoir and steam, hot air, solvents, or a combination thereof, can be injected to release the hydrocarbons. The released hydrocarbons may then be collected by other wells and brought to the surface. In another technique, 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, this technique produces a substantial amount of waste or tailings that must be disposed.

Another process for harvesting oil sands, which may generate less surface waste, is the slurrified hydrocarbon extraction process. In the slurrified hydrocarbon extraction process, the entire contents of a reservoir, including sand and hydrocarbon, can be extracted from the subsurface via wellbore for processing at the surface to remove the hydrocarbons. The tailings are then reinjected via wellbores back into the subsurface to prevent subsidence of the reservoir and allow the process to sweep the hydrocarbon bearing sands from the reservoir to the wellbore producing the slurry.

U.S. Pat. No. 5,832,631 to Herbolzheimer, et al., discloses one such slurrified hydrocarbon recovery process that uses a slurry that is injected into reservoir. In this process, hydrocarbons that are trapped in a solid media, such as bitumen in oil sands, can be recovered from deep formations. The process is performed by relieving the stress of the overburden and causing the formation to flow from an injection well to a production well, for example, by fluid injection. A oil sand/water mixture is recovered from the production well. The bitumen is separated from the sand and the remaining sand is reinjected in a water slurry.

International Patent Application Publication No. WO/2007/050180, by Yale and Herbolzheimer, discloses an improved slurrified heavy oil recovery process. The application discloses a method for recovering heavy oil that includes accessing a subsurface formation from two or more locations. The formation may include heavy oil and one or more solids. The formation is pressurized to a pressure sufficient to relieve the overburden stress. A differential pressure is created between the two or more locations to provide one or more high pressure locations and one or more low pressure locations. The differential pressure is varied within the formation between the one or more high pressure locations and the one or more low pressure locations to mobilize at least a portion of the solids and a portion of the heavy oil in the formation. The mobilized solids and heavy oil then flow toward the one or more low pressure locations to provide a slurry comprising heavy oil, water and one or more solids. The slurry comprising the heavy oil and solids is flowed to the surface where the heavy oil is recovered from the one or more solids. The one or more solids are recycled to the formation, for example, as backfill.

The method discussed above converts the hydrocarbon bearing reservoir into a formation resembling a moving bed. When the reservoir moves toward the producer wells, void space is filled by the reinjected clean slurry stream. The reinjected stream must have permeability that is higher than the relative permeability to water of the target formation. Thus, the slurry is not pushed, but rather dragged by the percolating fluid flow.

As mentioned, the formation can be conditioned to relieve the pressure of the overburden, for example, by injecting water until the pressure normalizes. This is described in U.S. Patent Application Publication No. 2010/0218954 by Yale, et al., entitled “Application of Reservoir Conditioning in Petroleum Reservoirs.” The application provides methods for recovering heavy oil. The process includes conditioning a reservoir of interest, then initially producing fluids and particulate solids such as sand to increase reservoir access. The initial production of a slurry may generate high permeability channels or wormholes in the formation, which may be used for hydrocarbon production processes such as cold flow (CHOPS) or enhanced production processes such as steam assisted gravity drainage (SAGD) or vapor extraction (VAPEX) techniques.

Most processes to recover hydrocarbons from subsurface formations involve the reduction in fluid pressure in the reservoir which can lead to compaction of the formation. The magnitude of this compaction is dependent upon the degree of pressure reduction and the stiffness of the formation. The compaction is sometimes used to help drive out fluids from the formation into the production wells and to the surface. Injection of fluid into formations during hydrocarbon recovery is also often used to either keep fluid pressure up (to help maintain sufficient pressure to drive fluids to the production wells) or to help sweep the in-situ hydrocarbons to the production wells. In general, significant compaction in reservoir formations is avoided due to the problems it can cause with the stability of wellbores into these formations and potential problems with the subsidence of the surface.

SUMMARY

An embodiment provides a method for recompacting a reservoir comprising detecting a slurry override condition and reducing a pressure within the reservoir so as to reapply a stress from an overburden to mitigate override during a hydrocarbon recovery process.

Another embodiment provides a method for harvesting a hydrocarbon from a sand reservoir. The method includes detecting a slurry override condition and reducing a pressure within the sand reservoir so as to reapply a stress from an overburden onto the reservoir sand.

Another embodiment provides a system for recompacting a reservoir, comprising an injection well, wherein the injection well is configured to inject a slurry comprising sand and fluid into the reservoir and a production well, wherein the production well is configured to produce a slurry comprising sand and hydrocarbon from the reservoir, wherein the injection well, the production well, or both is configured to allow recompaction of the reservoir.

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 diagram showing the use of a slurrified heavy oil reservoir extraction process to harvest hydrocarbons from a reservoir, such as an oil sands deposit;

FIG. 2(A) is a schematic of the initial state with the reservoir under stress from the pressure of the overburden;

FIG. 2(B) is a schematic of the conditioning process used to remove the stress of the overburden from the reservoir;

FIG. 2(C) is a schematic of a slurry production process, as described with respect to FIG. 1;

FIG. 2(D) is a schematic of an override condition, in which a portion of the mixed slurry overrides the reservoir and follows a direct path from the injection well to the production well;

FIG. 3 is a schematic of a recompaction process that recompacts the sand bed by producing fluid from both the injection wells and production wells;

FIG. 4 is a schematic of a recompaction process that recompacts the sand bed by shutting in the production well and producing fluid from the injection well;

FIG. 5 is a schematic of another recompaction process that recompacts the sand bed by shutting in the injection well and allowing fluid to be produced from the production well;

FIG. 6 is a schematic of a recompaction process based on an controlled imbalance between the slurry injection rate and the reservoir production rate;

FIG. 7 is a diagram showing a pattern of injection wells and production wells over a hydrocarbon field;

FIG. 8(A) is a schematic of production changes to injection wells and production wells that may be performed to recompact a target region of a reservoir;

FIG. 8(B) is another schematic of production changes to injection wells and production wells that may be performed to recompact a target region of a reservoir;

FIG. 9 is a process flow diagram of a method for producing hydrocarbons from a sand reservoir;

FIG. 10 is a drawing of a 210 cm diameter sand bed showing a colored sand flow (indicated by the hash marked area) through each of four injection arms;

FIG. 11 is a drawing of a resistivity image of the 210 cm diameter sandpack, illustrating loss of flow into one arm; and

FIG. 12 is a drawing of the resistivity image of a 210 cm diameter sandpack, illustrating restoration of flow into the arm after recompaction.

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.

“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.

“Clark hot water extraction process” (“CHWE”) was originally developed for releasing bitumen from oil sands, based on the work of Dr. K. A. Clark, and discussed in a paper by Corti, et al., “Athabasca Mineable Oil Sands: The RTR/Gulf Extraction Process Theoretical Model of Bitumen Detachment,” The 4th UNITAR/UNDP International Conference on Heavy Crude and Tar Sands Proceedings, vol. 5, Edmonton, AB, Aug. 7-12, 1988, pp. 41-44, 71. The process uses vigorous mechanical agitation of the oil sands with water and caustic alkali to disrupt the granules and form a slurry, after which the slurry is passed to a separation tank for the flotation of the bitumen, or other hydrocarbons, from which the bitumen is skimmed. The process may be operated at ambient temperatures, with a conditioning agent being added to the slurry. Earlier methods used temperatures of 85° C., and above, together with vigorous mechanical agitation and are highly energy inefficient. Chemical adjuvants, particularly alkalis, have to be utilized to assist these processes.

The “front end” of the CHWE, leading up to the production of cleaned, solvent-diluted bitumen froth, will now be generally described. The as-mined oil sand is firstly mixed with hot water and caustic in a rotating tumbler to produce a slurry. The slurry is screened, to remove oversize rocks and the like. The screened slurry is diluted with additional hot water and the product is then temporarily retained in a thickener vessel, referred to as a primary separation vessel (“PSV”). In the PSV, bitumen globules contact and coat air bubbles which have been entrained in the slurry in the tumbler. The buoyant bitumen-coated bubbles rise through the slurry and form a bitumen froth. The sand in the slurry settles and is discharged from the base of the PSV, together with some water and a small amount of bitumen. This stream is referred to as “PSV underflow.” “Middlings,” including water containing non-buoyant bitumen and fines, collect in the mid-section of the PSV.

The froth overflows the lip of the vessel and is recovered in a launder. This froth stream is referred to as “primary” froth. It typically comprises 65 wt. % bitumen, 28 wt. % water, and 7 wt. % particulate solids.

The PSV underflow is introduced into a deep cone vessel, referred to as the tailings oil recovery vessel (“TORV”). Here the PSV underflow is contacted and mixed with a stream of aerated middlings from the PSV. Again, bitumen and air bubbles contact and unite to form buoyant globules that rise and form a froth. This “secondary” froth overflows the lip of the TORV and is recovered. The secondary froth typically comprises 45 wt. % bitumen, 45 wt. % water, and 10 wt. % solids. The underflows from the TORV, the flotation cells and the dilution centrifuging circuit are typically discharged as tailings into a pond system. As used herein, the tailings are sources of particulate streams that may be separated into two or more substreams, for example, including particles of different sizes. Any discussions of particles will include tailings and vice-versa. In embodiments of the present techniques, the tailings are reinjected back into the formation as backfill. The reinjection both prevents subsidence as material is removed from the reservoir and also lowers environmental issues from the waste tailings. Water removed from the tailings during the reinjection process may be recycled for use as plant process water.

“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, sand processing plants, and delivery outlets. In some instances, the term “surface facility” is used to distinguish those facilities other than wells. A “facility network” is the complete collection of facilities that are present in the model, which would include all wells and the surface facilities between the wellheads and the delivery outlets.

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 bitumen, 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 is the millidarcy. The term “relatively permeable” is defined, with respect to formations or portions thereof, as an average permeability of 10 millidarcy or more (for example, 10 or 100 millidarcy). The term “relatively low permeability” is defined, with respect to formations or portions thereof, as an average permeability of less than about 10 millidarcy.

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

As used herein, “pressure gradient” represents the pressure differences divided by the distance between the locations where those pressure differences are measured. Pressure gradient is a measure of driving force moving the sand through the reservoir or the pressure moving slurries through a pipe.

As used herein, “overburden stress” is the stress that the overburden applies to the sands within the reservoir due to its weight. Overburden stress may be considered to be the effective stress applied by the overburden, e.g., the total stress of the overburden minus the fluid pressure within the reservoir sand. As such it is a measure of the stresses the sand grains in the reservoir sand exert on each other due to the weight of the overburden.

As used herein, “override” is a condition where the injected fluids or slurries flow from injector to producer with little or reduced movement of the hydrocarbon bearing sand in between the injector and producer. This override is generally the overriding of the injected fluids or slurries over the top of the hydrocarbon bearing sand due to the density of the reinjected material and/or the lack overburden stress on that portion of the hydrocarbon bearing sands in the reservoir. However, in this context, override may include any bypass, whether over the top of the sand, under the sand, or through the sand, where the reinjected materials pass from the injector to producer with significantly reduced pressure gradient between the injector and producer than before override and with significantly reduced or nearly zero movement of the hydrocarbon bearing sand towards the producing well in the region of the override or bypass.

As used herein, a “reservoir” is a subsurface rock formation from which a production fluid can be harvested. The rock formation may include 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 permeability of the reservoir provides the potential for production. As used herein a reservoir may also include a hot dry rock layer used for geothermal energy production. A reservoir may often be located at a depth of 50 meters or more below the surface of the earth or the seafloor.

A “sand filter” or well screen is a zone of perforated material that is either built into an end of a well pipe, or fitted as a sleeve over a very coarsely perforated part of the pipe. The well screen can be made from wire mesh, wire wound, perforated plate, or porous metal fiber material. The design of the well screen will be tailored to the size of the solid particles to be blocked, which is generally 50 μm or more. Generally, the sand in a heavy oil reservoir can vary in particle size from about 62.5 μm to greater than about 500 μm, so the screen aperture may be important. If the aperture is too large in relation to the sand's particle size, then a fluid rate will be higher, but too much sand will penetrate the screen. If the aperture is too close to the size of the particles, then the fluid may be clean, but the flow rate may be low and the screen may quickly block. As used herein, a sand filter may be included as a segment of a pipe in an injection well or a production well that is used during a recompaction process. The resulting fluid flow may not be completely free of sand, but may be substantially free of sand, e.g., without containing enough sand to effect the reservoir sand content.

“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.

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.” Further, multiple pipes may be inserted into a single wellbore, for example, to limit frictional forces in any one pipe.

Overview

As previously mentioned, hydrocarbons can be harvested from sand reservoirs by producing a slurry that includes both sand and hydrocarbons from a production well. The sand is processed to remove hydrocarbons, and reinjected as a slurry into the reservoir. However, in certain situations, the reinjected slurry can override the reservoir due to its lower density relative to the in-situ density of the reservoir and/or reduction in stress on the reinjection sand and/or excessive fluid in the reinjected slurry. In these cases, the reinjected slurry can travel directly from the injection wells to the production wells, decreasing or eliminating the pressure gradients needed to move the in-situ reservoir sand from the injector to producer. This is likely to reduce the ultimate recovery of the process, hurting the economics of the project. Further, the overall recovery from the slurrified heavy oil recovery process may be decreased by slurry override. Embodiments of the present invention provide a method and a system for recompacting a sand reservoir to prevent a lower viscosity slurry from overriding a lower layer and move from an injection well to a production well while bypassing hydrocarbon.

For effective injection of tailings, two conditions can be met. First, the permeability of the backfill solids can be controlled within a predetermined range of about 0.5 to about 100 times of the initial permeability of the injected fluid through the porous material of the subsurface formation into which the mixture is injected. Second, the slurry rheology can be controlled to manage pipe pressure losses. When both criteria are met, the backfill may be placed correctly, water consumption can be optimal, and subsidence may be prevented. More dilute slurries, i.e., higher water fraction, are sometimes needed in this initial startup phase as the extra water may helps to start the process. This leads to the potential for override of the less dense slurry if the excess water does not flow away from the reinjected slurry fast enough or the less dense slurry is injected for too long of a period.

Recompaction to Improve Performance

Some embodiments of current invention include various mining or civil engineering operations which rely on backfilling, such as reinjection or replacement, of part or the whole of produced formation underground. In particular in situ heavy oil mining operations, such as a slurrified heavy oil reservoir extraction method shown in FIG. 2, may benefit from the current invention.

FIG. 1 is a diagram 100 showing the use of a slurrified heavy oil reservoir extraction process to harvest hydrocarbons from a reservoir, such as an oil sands deposit. The slurry recompaction techniques described herein are not limited to the slurrified reservoir process but may be used with any number of other processes. For example, the techniques described herein may be used to recompact a separation column, recompact a slurry fill in a subsurface cavity, or perform any number of other recompaction operations. In the diagram 100, a reservoir 102 is accessed by an injection well 104 and a production well 106 drilled through an overburden 108 above the reservoir 102.

The reservoir is a subsurface formation that may be at a depth greater than about 50 meters. Water injection into the wells 104 and 106 can be used to raise the fluid pressure in the reservoir 102 and relieve the stress on the reservoir 102 from the overburden 108. The pressure at which the stress is relieved on the reservoir may be termed the conditioning pressure, as that is the pressure at which the reservoir is deemed sufficiently conditioned to allow sand flow from the reservoir. The conditioning pressure depends on the pressure from the overburden 108, e.g., due to the depth of the reservoir 102, and may be about 50 to about 1000 psi greater than the initial pressure. After the relief of overburden stress, a water and sand mixture can be injected through the injection well 104, for example, from a pumping station 110 at the surface 112. At the same time, hydrocarbon containing materials 114, such as oil sands, can be harvested from the reservoir 102, for example, through another pumping station 116. The hydrocarbon containing materials 114 may be processed in a facility 118 to remove at least a portion of the hydrocarbons 120. The hydrocarbons 120 can be sent to other facilities for refining or further processing. The cleaned tailings can be used to form a mixed slurry 122, including water and sand or other particulates, which may then be backfilled, i.e., reinjected into the reservoir 102, for example, to prevent subsidence of the surface 112. The injection well 104 and production well 106 are generally limited to single connections to the reservoir 102, but multiple injection and production wells 104 and 106 are often used over a reservoir.

The method converts the hydrocarbon bearing sands of the reservoir 102 into a formation resembling a moving bed that includes sand and hydrocarbon. When the reservoir 102 moves toward the production well 106, the void space can be continuously filled by a reinjected clean slurry stream, which can include clay, silt, sand, and fluid, from the injection well 104.

The slurry fill process, described above, may also influence the density of the sand in the reservoir 102. In combination with the initial conditioning step, this process may create a lower density slurry in an upper part of the reservoir 102, which could allow an injected mixed slurry 122 to at least partially override the hydrocarbon bearing sand and pass through the reservoir 102 without moving the hydrocarbon bearing slurry through the reservoir. The slurrified heavy oil recovery process is discussed further with respect to FIGS. 2(A)-(D).

FIG. 2(A) is a schematic of the initial state with the reservoir 102 under stress from the pressure of the overburden 108. In FIGS. 2(A)-(D), like numbered items are as discussed with respect to previous figures. Two wells may be completed to the reservoir 102, an injection well 104 and a production well 106. The wells 104 and 106 are not limited to injection or production, but may be converted as needed to serve either purpose, for example, during a conditioning or recompaction process. Further, as discussed further with respect to FIGS. 7 and 8, a number of injection wells 104 and production wells 106 may be used to access the reservoir 102.

FIG. 2(B) is a schematic of the conditioning process used to remove the stress of the overburden 108 from the reservoir 102. The conditioning is generally performed by fluid injection, for example, through one or more of the wells 104 and 106, as indicated by arrows 202. Once conditioning is completed, the stresses on the reservoir 102 are balanced, and frictional forces, which may tend to prevent the reservoir from being harvested, are decreased enough to allow the reservoir 102 to move. After this conditioning process, there remains some limited overburden stress on the hydrocarbon bearing reservoir sands. The magnitude of this stress is generally small (generally in the range of 10 to 400 kPa out of the 1 MPa to 10 MPa overburden stress that would have been on the sands before conditioning.

FIG. 2(C) is a schematic of a slurry production process, as described with respect to FIG. 1. In the production process, the clean, mixed slurry 122 is injected into the reservoir 102, creating a zone 204 containing the mixed slurry 122, which causes the reservoir 102 to slide from the vicinity of the injection well 104 to the vicinity of the production well 106, as indicated by arrow 206. From the production well 106, the hydrocarbon containing materials 114 can be produced.

FIG. 2(D) is a schematic of an override condition, in which a portion 208 of the mixed slurry 122 overrides the reservoir 102 and follows a direct path from the injection well 104 to the production well 106. In this case, the injected slurry bypasses the hydrocarbon containing materials of the reservoir 102. Based on experiments, override may occur because the overburden stresses on the sands within the overriding mixed slurry nearly completely disappear, for example, due to the presence of excess fluid pressure in the region or to the overburden stresses being supported by nearby non-moving portions of the reservoir sand. The override condition may be directly detected by the composition of the extracted material. The override condition may also be detected by a significant drop in the pressure gradient between the injector and producer, since it may take less pressure to drive the overriding material between injector and producer, than to drive the reinjected sands and hydrocarbon bearing sands between injector and producer when override is not occurring. Further, the loss of pressure gradient between injector and producer due to override may slow down or stop the movement of the hydrocarbon bearing sand and, thus, reduce the production of hydrocarbon bearing sand from the area in which override is occurring.

In an embodiment, override may be mitigated by recompaction of the reservoir sand. For example, the reservoir 102 may be either partially recompacted or returned to its original stress state. In some embodiments, the recompaction may be directed to the portion 208 of the mixed slurry 122 that is overriding the in-situ material. The recompaction of the reservoir 102 or the portion 208 may be used to bring the density of sand throughout the reservoir 102 to nearly the same state.

The recompaction may be performed by reducing the pressure in the reservoir 102, for example, by slowing or stopping the injection of the mixed slurry 122 or production of the hydrocarbon bearing materials 114, while allowing water production from the injection wells 104, production wells 106, or from both. This allows the stress from the overburden 108 to be at least partially reapplied to the reservoir 102, recompacting at least a portion of the sand in the reservoir 102. The reservoir pressure after the recompaction may be higher than the initial pressure in the reservoir 102, or may be at the initial pressure of the reservoir 102. In an embodiment, the reinjected sand in the portion 206 of the slurry mixture 122 that is overriding the reservoir 102 may be recompacted, sealing the path of the slurry override. In another embodiment, the pressure in the reservoir could be allowed to bleed off to other parts of the reservoir that may be at lower pressure.

The slurrified heavy oil recovery process can then restarted by repeating the conditioning phase discussed with respect to FIG. 2(B). The conditioning phase may be accomplished in a shorter times due to the presence of some higher permeability reinjected slurry and the higher water saturation of the recompacted reservoir system versus the original in-situ reservoir system and restarting slurry production and reinjection. As the sands have been recompacted, it is believed the process will allow ultimate recoveries to be similar to what they would have been if override never occurred. The techniques that may be used for recompacting the reservoirs in various embodiments is discussed in greater detail with respect to FIGS. 3-6.

FIG. 3 is a schematic of a recompaction process 300 that recompacts the sand bed by producing fluid from both the injection wells 104 and production wells 106. In FIG. 3, like numbered items are as discussed with respect to previous figures. The fluid production, indicated by arrows 302, may be performed by allowing flow at a reduced rate, which may lower entrainment of sand. The fluid production 302 may also be performed through a sand filter, such as a limited entry perforation (LEP) segment. The LEP may be included as a portion of the well during the initial completion or may be placed in one or both wells 104 and 106 at a later time.

FIG. 4 is a schematic of a recompaction process 400 that recompacts the sand bed by shutting in the production well 106 and producing fluid 302 from the injection well 104. In FIG. 4, like numbered items are as discussed with respect to previous figures. As in the previous recompaction process, the injection well 104 may have an LEP segment to allow the fluid production 302 without entrained sand. However, the proportion of fines in the reinjected slurry mixture 122 may be lower than in the sand of the reservoir 102. This may allow for higher production rates of fluid 302 without solid entrainment from the injection well 104 as the zone 204 comprising the mixed slurry 122 may act as a sand filter. In addition, since the reinjected sand would have substantially no hydrocarbons, with the possible exception of a small amount left over after the surface extraction process, the ability to produce water out of the injection wells would likely be easier than producing it out of the production wells due to the higher permeability to water of the sands around the injection well as compared to that around the producing wells.

FIG. 5 is a schematic of another recompaction process 500 that recompacts the sand bed by shutting in the injection well 104 and allowing fluid 302 to be produced from the production well 106. In FIG. 5, like numbered items are as discussed with respect to previous figures. As described herein, a LEP segment may be included in the production well 106 to allow the fluid 302 to be produced without entrained sand. In addition, other methods may be used to prevent sand production while water production is being attempted. These could include, but are not limited to, sand screens, slotted liners, or gravel packs in addition to the LEPs mentioned earlier.

The recompaction does not have to be performed by completely shutting in the wells 104 or 106. In an embodiment of the process, slurry injection can be continued, while only fluid is withdrawn from the production well 106 rather than a fluid and sand slurry, as described with respect to FIG. 6. In an embodiment, slurry injection could continue in some injection wells while other injection wells are used to produce fluid only for reasons stated above.

FIG. 6 is a schematic of a recompaction process 600 based on a controlled imbalance between the slurry injection rate and the reservoir production rate. In FIG. 6, like numbered items are as discussed with respect to previous figures. This may be performed using any number of combinations of injection and production rates. For example, the injection rate of the slurry may be decreased, as indicated by the dotted arrow 602, while the production rate, indicated by the solid arrow 604 is held constant.

In other embodiments, the injection rate 602 of the slurry may be held constant while only fluid is produced from the production well 106. In this embodiment, a LEP segment may be included in the production well 106 to assist in the production of fluid without entrained sand. The production of only fluid while injecting denser slurry allows the reinjected material in the override area 208 to become denser and thus support the overburden stress.

FIG. 7 is a diagram showing a pattern 700 of injection wells 702 and production wells 704 over a hydrocarbon field 706. The hydrocarbon field 706 generally overlies a single reservoir 102, for example, as discussed above. The pattern 700 may generally be referred to as a “five-spot pattern,” in which four injection wells 702 surround a central production well 704. Generally, the pattern 700 can be repeated multiple times across a hydrocarbon field 706, so that the number of injection wells 702 and production wells 704 are matched, which assists with maintaining a mass balance of material entering and exiting the reservoir. As shown in FIG. 7, the pattern 700 may be regularly spaced across a field. In other embodiments, the wells 702 and 704 may be irregularly spaced, for example, placed to improve interaction with the reservoir geometry. Any number of other patterns may be used in embodiments.

While the slurrified heavy oil recovery method relies on multiple, repeated patterns of injectors and producers, the selected recompaction scheme does not necessarily need to be applied to the entire reservoir 102. For example, if an override condition is detected only in on portion of the reservoir 102, a recompaction process may be implemented only on that section. This is discussed further with respect to various patterns in FIG. 8. The patterns are not limited to those shown in FIG. 8, but may be implemented using any number of patterns. A pattern-by-pattern decision can be made based on local production and injection information, for example, depending on the size, shape, or reservoir configuration in the area of the override.

FIG. 8 (A) is a schematic of production changes to injection wells and production wells that may be performed to recompact a target region 800 of a reservoir. In this example, production rates for injection wells 802 and production wells 804 outside of the target region 800 may not be changed. However, production wells 806 surrounding the target region 800 may be operated at a reduced rate and wells 808 within the target region 800 may be shut-in. This may allow a slow subsidence of the target region, for example, by fluid draining to other regions or to the surrounding formations, providing recompaction of the sand bed within the target region 800.

FIG. 8(B) is another schematic of production changes to injection wells and production wells that may be performed to recompact a second target region 810 of a reservoir. In this example, the second target region 810 includes the opposing “arms” of a five-spot pattern. A partial recompaction, for example, a few psi to a few tens of psi, may be performed by shutting in a single producer 812 and two opposing injection wells 814, and reducing rates from the surrounding production wells 806.

The techniques are not limited to the patterns and embodiments shown above, but may use any combinations of wells that are shut-in, producing at reduced rates, or merely producing fluid. For example, production or production and injection may be shut down in an area and the pressures in the area may be allowed to equilibrate before starting up production and injection again. This may be performed to mitigate the pressure gradients causing an override.

The techniques described herein allow for the re-application or re-distribution of overburden stresses on the reservoir sand. In some cases, such as a full or nearly full reapplication of overburden stresses, the stresses are redistributed so that certain parts of the reservoir sand, such as the non-moving sections, are compacted. This may redistribute the stresses on those portions of the reservoir to the parts of the sand where slurry injection and slurry production were occurring. In other cases, the redistribution of stresses and pore pressure may be milder and the override can be avoided upon restart due to the bleed off of fluid pressures from the override area as much as by the redistribution of stresses.

In addition to reducing fluid pressure and recompacting the sand, the techniques described herein have the beneficial outcome of making the sand, fluid pressures, and stresses on the sand in the reservoir more homogenous. The processes discussed above may lead to inhomogeneities in sand permeability or pressure or stress distributions, which can lead to override or bypass. As such, the homogenization of those properties of the sand in the reservoir also act as a method to help prevent override once injection and production is restarted.

FIG. 9 is a process flow diagram of a method 900 for producing hydrocarbons from a sand reservoir. The method 900 begins at block 902 when an injection well is completed to a reservoir. Although the injection well will generally be used for slurry injection, the injection well may also include a limited entry perforation (LEP) section, or other type of sand trap, that allows fluid to flow without entrained sand when selected. At block 904, a production well is completed to the reservoir. As in the case of the injection well, the production well may also have a segment containing a sand trap.

At block 906, the reservoir can be conditioned for slurry flow. This is performed by injecting fluid into the reservoir through the injection wells, the production wells, or both, until the pressure in the reservoir is normalized with the pressure of the overburden. The normalization releases friction in the reservoir, allowing the reservoir to move from the injection well to the production well.

At block 908, slurry may be injected in the injection well to cause the reservoir to flow towards the production well. At block 910, hydrocarbon containing slurry can be produced from the reservoir through the production well. Produced materials can be cleaned and reinjected as a mixed slurry, while the hydrocarbon may be transported for further processing. The reinjected mixed slurry replaces the material that is produced. However, under some circumstances the reinjected mixed slurry may override the hydrocarbon containing sands of the reservoir, leading to the production of lower amounts of hydrocarbon than would otherwise occur.

At block 912, the override condition may be detected. This may be performed using any number of techniques. For example, a sudden decrease in expected hydrocarbon from certain wells may be noted. Further, a change in particle size distribution may indicate that the injected mixed slurry is passing directly from the injection well to the production well, bypassing the reservoir.

At block 914, pressure is lowered on the reservoir to recompact the sand bed. As discussed herein, this may be performed by any number of techniques that allow increased production of fluids or slurry from the reservoir versus injection of slurry into the reservoir. For example, in an embodiment, injection may be slowed or stopped, while keeping production constant. In another embodiment, injection and production may be stopped in the area of the override, while production at reduced rates continues from wells surrounding the area of the override. In another embodiment, injection may be halted and fluid may be produced from injection wells, production wells, or both.

At block 916, injection and production may be resumed. This may be proceeded by a repeat of the conditioning step to relieve pressure on the reservoir. The conditioning step may take less time or less fluid than the initial conditioning step. The method 900 may be repeated any number of times during the life of the reservoir.

EXAMPLES

The techniques described herein were tested in a laboratory at two different scales, using a 25 cm diameter sandpack and a 210 cm diameter sandpack as model reservoirs. The test procedures and apparatus for the 210 cm diameter sandpack are as described in David P. Yale, et al., “Large-Scale Laboratory Testing of the Geomechanics of Petroleum Reservoirs,” SPE 134313, presented at the 44th US Rock Mechanics Symposium and 5th U.S.-Canada Rock Mechanics Symposium, held in Salt Lake City, Utah, Jun. 27-30, 2010. The test procedures for the 25 cm are similar to those described in Yale et. al.

FIG. 10 is a drawing 1000 of a 210 cm diameter sand bed showing a colored sand flow (indicated by the hash marked area) through each of four injection arms 1002-1008. An injection arm is the area between any given injection well 1010 and the production well 1012. The colored sand was mixed with the injected sand as a material marker. As shown in this drawing 1000, the tests were set up as single five-spot patterns, using four equidistant injector wells 1010 and a center single producer well 1012. Real reservoir sands and model fluids were used to mimic actual reservoir mobility and ensure the slurrified heavy oil recovery experiments were representative. A similar configuration was used for the sandbed in the 25 cm diameter cell. In this example, the flow into all four injection arms 1002-1008 is visually illustrated, showing a restoration of flow after an override condition, as is discussed further with respect to FIGS. 11 and 12.

In one such test in the 25 cm diameter cell, production of the colored reinjected sand was observed well before mass balance calculations suggested the majority of the in-situ sand had been produced. This, in addition to pressure gradients measured in the cell, suggested that the re-injected slurries were overriding the in-situ sands and not allowing as much of the in-situ sands to be produced. In one such test, this override was observed to occur in just one of the four injection arms. In another test, this override was observed in two of the injection arms. In these tests, the injection and production of slurries was suspended and fluid only production was done until the fluid pressure in the cell was reduced to nearly the same pressure as was in the cell before the “conditioning” portion of the test. This reapplied the stress on the sandpack in the cell that simulated the stress on a reservoir sand before the start of the “conditioning” part of a slurrified heavy oil extraction process.

After the pressure reduction and stress re-application, the conditioning was repeated, i.e., fluid pressure raised to nearly the overburden pressure applied to the sand. Then the slurry production and injection process was restarted as described in Yale and Herbolzheimer. In this test, the slurry production and slurry injection was able to proceed to full production of the in-situ sand and achieve a sweep efficiency of over 70%, i.e., 70% of the in-situ or initial sand in the area between the injectors and producers was swept to and produced up the production well.

During two tests in the 210 cm diameter cell, recompaction was used to allow slurry injection-production to be re-started after early breakthrough and other problems. In one case override was observed in all four injection arms 1002-1008 after only about 20% of sweep and thus production was stopped. Investigation of the reason for the override suggested that the injected slurry had more water than usual, i.e., was less dense than usual, and this led to the override both from the perspective of a less dense slurry but also by allowing overburden stresses on the sands to decrease, which has been observed to lead to override.

Rather than decreasing the fluid pressure to initial conditions, a slightly different approach was taken where production of water only was started in the production well 1012 and injection of a denser (less water) slurry was started in each of the four injection wells 1010. After the pressure was decreased by several psi and stresses were reasserted on the sand from the dense slurry injection, water production was stopped while slurry injection continued. Once fluid pressure recovered to the levels sufficient for the start of slurry production/injection (i.e. full conditioning), production of slurry was restarted. Injection/production of slurry through to full sweep was then achieved.

In addition to early production of colored sand, other techniques were used to identify slurry override conditions. For example, the 210 cm diameter cell is wired with a number of sensors for resistivity analysis of the sands in the cell. The resistivity images can be used to identify which injection arms are showing override conditions, for example, by initially charging the sand bed with a high resistivity solution, then using a low resistivity solution for the liquid base in a slurry. In addition, a significant drop in the pressure gradient between the injector and producer (as evidence by the measurement of pressure at a number of points between the injector and producer) was seen when the override occurred.

FIG. 11 is a drawing of a resistivity image of a cross-section of the 210 cm diameter sandpack, illustrating loss of flow through one injection arm 1004. In FIG. 11, like numbered items are as discussed with respect to FIG. 10. In both FIGS. 11 and 12, a higher resistivity area of the original sand bed is indicated by small x's, while a lower resistivity area is indicated by small o's for the liquid slurry added to the sandpack by the injection wells. Further, it should be understood that FIG. 11 is a two dimensional cross section of a three dimensional phenomenon measured along the bottom of the sandpack. Accordingly, changes in resistivity may be greater in different layers.

Injection and production was started and sustained in the other three injection arms 1002, 1006, and 1008. However, it was surmised that there was an override of the initial fluid injected into arm 1004 preventing the establishment of a sufficient pressure gradient to move the sand between the injection well 1010 for injection arm 1004 and the production well 1012. This is seen in FIG. 11 in which the illustrated cross-section of the sandpack is below the overrride of the injected, low resistivity solution and the higher resistivity sand is not being swept towards the production well 1012. After allowing injection and production in the other three arms to proceed to full sweep, a partial recompaction was attempted to recompact the sand in the injection arm 1004, and in the rest of the sandpack, sufficiently to allow for sand flow to be started in injection arm 1004.

FIG. 12 is a drawing of the resistivity image of a 210 cm diameter sandpack, illustrating restoration of flow into the injection arm 1004 after the recompaction. In FIG. 12, like numbered items are as discussed with respect to FIG. 10. A recompaction of 40 psi, or 5% of the conditioning pressure, was applied to the sandpack and then the sandpack was reconditioned to full conditioning pressure. The test was restarted and slurry injection and production was initiated successfully in all four injection arms 1002-1008. Further, injection and production in injection arm 1004 through to full sweep was successful post recompaction. FIG. 10, above, shows the visual image post test of the swept sections of the original sand and the effectiveness of the recompaction.

Repeating the conditioning process to relieve the overburden stress applied during the recompaction is required after each recompaction to bring the sandpack to the fully conditioned state needed to produce and inject slurry. Slurry production and slurry reinjection were then restarted, with the vast majority of the subsequent production being from the initial, in-situ material, which indicated successful healing of the override in the various examples above.

The process was run until normal breakthrough occurred, e.g., when the vast majority of the production was of the reinjected material. Examination of the sandpacks after the test showed a high recovery factor, which was similar to results from tests where override did not occur. There was no particular evidence in the recompacted sandpack that override had ever occurred.

The examples above suggest that the recompaction process can be used in a number of different embodiments, e.g., a very small amount of recompaction, a moderate amount of recompaction, or a full recompaction to the initial reservoir conditions that existed before the conditioning process was first applied to the reservoir. The examples show that the recompaction can correct a range of override problems from override of the reinjected sand to override of just the fluid being injected. The examples also show that the override can occur due to a low density of the injected slurry or due to imbalances in the application of overburden stress to various portions of reservoir sand. They also show that recompaction can be used to correct problems in just one injection arm of a five-spot pattern to two or more injection arms of a five-spot pattern. By extension, they also suggest that the recompaction process can be used on a single five-spot pattern or multiple five-spot patterns and to single or multiple injection arms in each of those five-spot patterns.

The process described herein may be used in slurrified heavy oil recovery to recompact the overriding sand to an absolute permeability which is similar enough to the permeability to water of the in-situ sand to allow the slurrified process to work. Therefore, the pressure drop across both the overriden material and the in-situ material is similar during subsequent injection-production and the entire sandpack is produced rather than preferential production of the overriding material.

While the present techniques may be susceptible to various modifications and alternative forms, the exemplary 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 method for recompacting material in a reservoir, comprising:

detecting a slurry override condition; and

reducing a pressure within the reservoir so as to reapply a stress from an overburden.

2. The method of claim 1, comprising injecting fluid into the reservoir to increase the pressure to a conditioning pressure.

3. The method of claim 1, wherein reducing the pressure comprises lowering a slurry injection rate while a production rate is maintained constant.

4. The method of claim 1, wherein reducing the pressure comprises lowering a slurry injection rate while increasing a production rate.

5. The method of claim 1, wherein reducing the pressure comprises maintaining a constant slurry injection rate while a production rate is increased.

6. The method of claim 1, wherein reducing the pressure comprises producing substantially only fluid from the reservoir.

7. The method of claim 1, wherein the reservoir is an oil sands formation.

8. The method of claim 1, wherein the reduced pressure is greater than an initial reservoir pressure.

9. The method of claim 1, wherein the reduced pressure is less than a conditioning pressure.

10. A method for harvesting a hydrocarbon from a sand reservoir, comprising:

detecting a slurry override condition; and

reducing a pressure within the sand reservoir so as to reapply a stress from an overburden onto the reservoir sand.

11. The method of claim 10, comprising:

removing at least a portion of a reservoir material from the sand reservoir;

processing the reservoir material to remove at least a portion of associated hydrocarbons and form a clean material;

forming a mixture comprising at least a portion of the clean material; and

reinjecting at least a portion of the mixture into the sand reservoir.

12. The method of claim 10, wherein fluid or slurry are withdrawn from the sand reservoir through injection wells, production wells, or both.

13. The method of claim 10, comprising reducing the pressure within the sand reservoir by allowing fluid to leak-off to a surrounding formation.

14. The method of claim 10, wherein the pressure in the reservoir is raised up to the conditioning pressure once sufficient recompaction has occurred to allow slurry production and slurry injection to be restarted without override.

15. The method of claim 10, wherein the amount of recompaction is sufficient to restart slurry production and slurry injection without override.

16. The method of claim 10, comprising:

injecting a slurry mixture into the reservoir through a plurality of injection wells; and

producing a reservoir material through a plurality of production wells.

17. The method of claim 16, comprising reducing the pressure within the reservoir by stopping injection of the slurry mixture into at least a portion of the plurality of injection wells.

18. The method of claim 16, comprising reducing the pressure within the reservoir by slowing injection of the slurry mixture into at least a portion of the plurality of injection wells.

19. The method of claim 16, wherein fluid is withdrawn from the reservoir through the plurality of injection wells.

20. The method of claim 16, wherein fluid is withdrawn from the reservoir through one or more production wells while injection of slurry is continued through one or more injection wells.

21. A system for recompacting a reservoir, comprising:

an injection well, wherein the injection well is configured to inject a slurry comprising sand and fluid into the reservoir; and

a production well, wherein the production well is configured to produce a slurry comprising sand and hydrocarbon from the reservoir, wherein the injection well, the production well, or both is configured to allow recompaction of the reservoir.

22. The system of claim 21, wherein the injection well, the production well, or both comprise at least a segment comprising a sand filter configured to filter sand from a produced fluid.

23. The system of claim 21, wherein the injection well is configured to allow the production of fluid substantially free of entrained sand from the reservoir.

24. The system of claim 21, wherein the production well is configured to allow the production of fluid substantially free of entrained sand from the reservoir.