SUBTERRANEAN FLOW BARRIERS CONTAINING TRACERS

Abstract

Some aspects of the present disclosure include monitoring fluid flow in a subterranean reservoir. In some implementations, a sealant mixture is injected into a subterranean reservoir to form a flow barrier in the subterranean reservoir. The sealant mixture includes a sealant material and a tracer. The tracer may be stored in the flow barrier, and the tracer may be displaced from the flow barrier, for example, by fluid flow in the subterranean reservoir. The displaced tracer may be detected, for example, in fluid produced into a well bore in the subterranean reservoir. Fluid flow in the subterranean reservoir may be analyzed based on detection of the tracer.

Description

BACKGROUND

Production of resources from a subterranean reservoir can be enhanced by injecting fluids into the reservoir to displace or sweep the resources to a production well. For example, water, steam, and/or other fluids are injected into subterranean reservoirs to induce migration of oil and gas resources to nearby production wells. The permeability of the reservoir rock, the connectivity of fractures in the reservoir, and other factors influence how the injected fluids and hydrocarbons flow through the reservoir. Fractures are typically formed in a reservoir to increase the fluid conductivity of the reservoir. Non-conductive barriers may also be formed in the reservoir to prevent the flow of fluid in a certain region of the reservoir. Such non-conductive barriers can be formed by injecting low permeability materials into fractures in the reservoir, including hydraulically induced fractures and/or natural fractures. The resulting non-conductive barriers divert the flow of injected water or steam, and thereby increase the volume of the reservoir swept by the injected fluids.

SUMMARY

In a general aspect, a tracer is stored in a subterranean flow barrier. The tracer may be released or displaced from the flow barrier and detected. In some cases, fluid flow may be analyzed based on the tracer.

In one aspect, a method for monitoring fluid flow in a subterranean reservoir includes injecting a sealant mixture into a subterranean reservoir to form a flow barrier in the subterranean reservoir. The sealant mixture includes a sealant material and a tracer. The tracer may remain in the flow barrier for a period of time. The tracer is displaced from the flow barrier by fluid flow in the subterranean reservoir, and the displaced tracer is detected.

Implementations may include one or more of the following features. Detecting the tracer includes detecting the tracer in fluids received into a well bore in the subterranean reservoir. The fluid flow includes flow of a treatment fluid injected into the subterranean reservoir through a different well bore. Injecting the sealant mixture includes injecting a chemical tracer mixed with the sealant material. Injecting the sealant mixture includes injecting at least one of a radioactive tracer mixed with the sealant material, a noble gas tracer mixed with the sealant material, a radio frequency tracer device mixed with the sealant material, a water-soluble tracer mixed with the sealant material, and/or a hydrocarbon-soluble tracer mixed with the sealant material. Injecting the sealant mixture includes injecting the sealant mixed with a tracer, where the tracer includes a coating adapted to dissolve when contacted by a particular fluid. The sealant in the subterranean reservoir prevents fluid flow through the flow barrier. The sealant mixture is a first sealant mixture that includes a first tracer. A second sealant mixture includes a second tracer. The second sealant mixture is injected into the subterranean reservoir to form a second flow barrier in the subterranean reservoir. The second tracer is displaced from the second flow barrier by fluid flow in the subterranean reservoir. The second tracer displaced from the second flow barrier is detected. The first sealant mixture forms a first portion of the flow barrier. A second sealant mixture is injected into the subterranean reservoir to form a second portion of the flow barrier. The second tracer is displaced from the flow barrier by fluid flow in the subterranean reservoir. The second tracer displaced from the flow barrier is detected.

In one aspect, a system for monitoring fluid flow in a subterranean reservoir includes a treatment well and a detector. The treatment well injects treatment fluid into a subterranean reservoir to displace hydrocarbon fluid in the subterranean reservoir. The subterranean reservoir includes a flow barrier that stores a tracer. The detector is adapted to detect the tracer displaced from the flow barrier by the hydrocarbon fluid and/or the treatment fluid.

Implementations may include one or more of the following features. The detector includes a down hole detector installed in the well bore and adapted to detect the tracer released from the flow barrier. The detector includes a detector located exterior the well bore and adapted to detect the tracer released from the flow barrier. The system includes a computing subsystem that analyzes fluid flow in the subterranean reservoir based on data provided by the detector. The treatment fluid is water and the hydrocarbon fluid is oil. The tracer includes a salt stored in the barrier. Detecting the tracer includes detecting a change of resistivity of the hydrocarbon fluid and/or the treatment fluid.

In one aspect, a method for analyzing fluid flow in a subterranean reservoir includes forming a flow barrier in a subterranean reservoir. The flow barrier includes a tracer. Fluid flow in the subterranean reservoir is analyzed based on detecting the tracer in fluids received into a well bore from the subterranean reservoir.

Implementations may include one or more of the following features. Analyzing fluid flow in the subterranean reservoir includes identifying that the fluids contacted the flow barrier in the subterranean reservoir. Analyzing fluid flow in the subterranean reservoir includes identifying a breach in the flow barrier. Forming the non-conductive barrier includes injecting the tracer and a sealant material into the subterranean reservoir. Analyzing the fluid flow includes identifying a direction of fluid flow in the subterranean reservoir. Geological features of the subterranean reservoir, for example geological heterogeneity, causes fluid to flow in multiple different directions, and analyzing the fluid flow includes identifying the directions of fluid flow and/or the geological features. An injection treatment is designed and/or modified based on detecting the tracers and/or on the analysis of the fluid flow. Designing the injection treatment includes selecting a location to inject treatment fluid, selecting a volume of treatment fluid to inject, selecting properties of a flow barrier to be formed. The injection treatment may be designed and/or modified to improve recovery of hydrocarbons from the reservoir.

DESCRIPTION OF DRAWINGS

FIG. 1 is a diagram of an example well system that includes a barrier in a subterranean reservoir.

FIG. 2 is a diagram of an example well system storing reservoir tracers in subterranean barriers.

FIG. 3 is a diagram of an example treatment well.

FIG. 4 is a diagram of an example well system detecting tracers released into a subterranean reservoir from a barrier.

FIG. 5 is a diagram of an example well system detecting tracers released into a subterranean reservoir from a barrier.

FIG. 6 is a flow chart showing an example technique for analyzing fluid flow in a reservoir.

FIGS. 7A-7D are diagrams of subterranean reservoir properties from example simulations.

Like reference symbols in the various drawings indicate like elements.

DETAILED DESCRIPTION

FIG. 1 is diagram of an example well system 100. The example well system 100 includes a production well 103 and treatment well 104 in a subterranean region 101 beneath a surface 102. The well system 100 can include one or more additional production wells and/or one or more additional treatment wells. The example production well 103 shown in FIG. 1 includes a horizontal well bore, and the example treatment well 104 shown in FIG. 1 includes a vertical well bore. However, production wells and treatment wells in the well system 100 may include any combination of horizontal, vertical, slant, curved, and/or other well bore geometries. The subterranean region 101 may include a reservoir 105 that contains hydrocarbon resources, such as oil, natural gas, and/or others. The reservoir 105 may include porous and permeable rock containing liquid and/or gaseous hydrocarbons. The reservoir 105 may include a conventional reservoir, a non-conventional reservoir, a tight gas reservoir, and/or other types of reservoir. The well system 100 produces the resident hydrocarbon resources from the reservoir 105 to the surface 102.

A production well 103 may extend through a hydrocarbon-containing subterranean formation area and into a water-bearing area. The water-bearing area may include, for example, fresh water, saltwater (e.g., water containing one or more salts dissolved therein), brine (e.g., saturated saltwater), and/or similar fluids. Typically, the water-bearing area may include a small proportion of hydrocarbon and/or other materials, the hydrocarbon-bearing area may include a small proportion of water and/or other materials, and the areas may overlaps in an intermediate area containing varying proportions of water and hydrocarbons. In some implementations, the water may come from a variety of sources, including in-situ water, injected water, or water entering the reservoir from an external source. For example, the water may be introduced into the formation through the injection well 104.

The reservoir 105 includes multiple subterranean fractures 106 in fluid communication with the production well 103. The fractures 106 may include fractures formed by a fracture treatment applied through the production well 103, natural fractures, complex fractures, and/or a network of propagated and natural fractures. For example, in addition to the bi-wing fractures shown in FIG. 1, the reservoir 105 may include a complex fracture network with multiple connected fractures at multiple orientations. The fractures 106 may extend at any angle, orientation, and azimuth from the production well 103. The fractures 106 include transverse fractures, longitudinal fractures (e.g., curtain wall fractures), and/or deviated fractures that extend along natural fracture lines. Hydraulically propagated fractures may have a geometry, size and/or orientation determined by injection tool settings.

The fractures 106 may contain proppant material injected into the fractures 106 to hold the fractures 106 open for resource production. Fluids typically flow more readily through the fractures 106 than through the rock and/or other geological material surrounding the fractures 106. For example, in some instances, the permeability of the rock in the reservoir 105 may be several orders of magnitude less than the permeability in the fractures 106.

The subterranean region 101 includes multiple barriers 108 adjacent the production well 103. Each barrier 108 includes sealant material that inhibits fluid flow in the barrier 108. The sealant material can include a low-permeability material. In some implementations, the permeability of the barrier 108 can be slightly less than or significantly less than the permeability of the reservoir 105 surrounding the barrier 108. In some implementations, a fracture may be partially sealed in an area near the well bore rather than completely sealed all the way to the fracture tip. Sealing the near well bore area may partially divert injection fluids to improve sweep.

As shown in FIG. 1, the well bore 103 includes a fluid control unit 107 that can prevent axial flow through the well bore that would circumvent the flow barrier 108. For example, a bridge plug or other zonal isolation device may be installed in the well bore to prevent axial flow through the well bore that would circumvent the flow barrier 108.

Fluid flow within a reservoir may be modified by the presence of a barrier. Selective or non-selective flow barriers may modify flow patterns within an entire reservoir or portions of a reservoir. In some implementations, a sealant that includes a relative permeability modifier may allow hydrocarbon materials to selectively flow through the barrier in relation to an aqueous fluid. In some implementations, multiple barriers may have varying permeabilities, and a series of barriers may guide the flow of at least one desired fluid, for example, to a producing well. In some cases, multiple selective and/or non-selective barriers may be used to modify the flow regime inside the hydrocarbon reservoir to improve the volumetric sweep efficiency of the hydrocarbons in the formation. The sealant and fluid used to provide the driving force for flow and sweep the hydrocarbon fluids can be selected to improve and/or maximize the amount of hydrocarbons recovered in a hydrocarbon reservoir.

A barrier 108 can be formed by injecting sealant material into the reservoir, for example, through the production well 103 and/or another well. Injecting the sealant material may fracture the reservoir rock as the sealant is injected, and/or the sealant material may be injected into existing fractures. For example, the sealant may be injected into fractures previously formed by a fracture treatment, natural fractures, complex fractures, and/or a network of propagated and natural fractures. The barriers 108 may extend at any angle, orientation, and azimuth from the production well 103. The barriers 108 may include variations in size, shape, thickness, permeability, and/or variations in other characteristics. In some implementations, the reservoir 105 includes barriers that are not adjacent to a production well bore. The sealant may be injected in an existing fracture by squeezing the sealant into the fracture, which may be accomplished, for example, by isolating perforations adjacent to the existing fracture using a packer on the end of tubing, then pumping the sealant in a fluid state through the tubing and through the perforations and into the fracture to be sealed until a sufficient volume of sealant has been placed into the fracture to provide the flow barrier.

Treatment fluids 110 are injected into the reservoir 105 through the treatment well 104 to induce migration of the resident hydrocarbon resources to the production well 103. For example, steam, water, gas, compressed air and/or other types of treatment fluids may be injected into the reservoir 105 through the treatment well 104. The injected treatment fluid 110 can displace or sweep oil, gas, and/or other resources into the production well 103, for example, via the fractures 106. The injected treatment fluid 110 may be injected in connection with a fireflood treatment, steam assisted gravity drainage treatment, and/or many other types of treatments that mobilize hydrocarbons in the reservoir 105. Barriers 108 in the reservoir 105 may influence the flow of treatment fluids 110 and hydrocarbon resources in the reservoir 105. The barriers 108 can be designed to improve sweep efficiency in the reservoir 105. The arrows 116 show an example pattern of fluid flow through the reservoir 105, where the flow is diverted by the barriers 108. As illustrated by the arrows 116 in FIG. 1, the treatment fluid 110 flows through the reservoir 105 toward the production well 103, contacts the barriers 108, and flows into the production well 103 through the fractures 106. In the example shown, the barriers 108 divert the treatment fluid 110 away from the production well 103 and cause the treatment fluid to sweep a larger region of the reservoir 105. Increasing the volume of the reservoir 105 that is swept by the treatment fluid 110 may enhance resource production from the reservoir 105. Barriers may be designed to influence fluid flow in the reservoir 105 in a different manner than the examples shown.

As shown in FIGS. 2, 4, and 5, barriers may contain reservoir tracers that can be used to analyze the flow of fluid in the reservoir 105. The tracers can be stored in the barriers 108, 208, 408, 508a, 508b. In some implementations, tracers stored in a barrier reside in or near the barrier until an event causes the tracer to be displaced from the barrier in the reservoir. When a tracer is displaced from the barrier, it may be released and/or transported out of and/or away from the barrier. Contact by a particular type of fluid and/or other events may cause the tracer to be displaced from the barrier. Tracers stored in a barrier may reside in or near the barrier for hours, days, weeks, months, years, or longer before the tracers are displaced from the barrier, for example, by fluid flow in the reservoir. In some instances, the treatment fluid 110 is injected with treatment fluid tracers through the treatment well 104. Such treatment fluid tracers injected with the treatment fluid 110 are traditionally used to identify the treatment well 104 as the source of the treatment fluid 110. The tracers stored in the barriers are injected with the sealant that forms the barriers, rather than being injected with the treatment fluid 110. As such, the tracers stored in the barriers may be used in some cases to identify and/or analyze additional and/or different types of information than the traditional treatment fluid tracers injected with the treatment fluid 110.

The production well 103, the reservoir 105, and/or other locations can be monitored for tracers that have been transported from the barriers 108 into the formation 105. Detecting such tracers may provide information on fluid flow in the reservoir 105. For example, detecting the tracer may indicate that the fluid containing the tracer interacted with one or more of the barriers 108. Detecting the tracers may provide additional and/or different information. For example, detecting tracers may provide spatio-temporal information regarding fluid flow patterns in the reservoir 105. Fluid flow patterns may indicate the location of a barrier breach, connectivity of subterranean fractures, rates of fluid flow in the reservoir 105, regions of low fluid conductivity in the reservoir 105, regions of high fluid conductivity in the reservoir 105, and/or other information. Detecting tracers may indicate a type of fluid (e.g., oil, water, etc.) contacting the barrier 108, and/or other information regarding fluid flow in the reservoir 105. Detecting tracers may indicate a level of stress in the reservoir, for example, when the tracers are designed to be released into the reservoir 105 by stress in the barriers 108.

In some implementations, a computing system analyzes data received from a tracer detection subsystem and analyzes the data to provide information describing fluid flow in the reservoir 105. For example, the computing system may receive input data relating to the time the tracer was detected, the location where the tracer was detected, the type of tracer detected, the amount of tracer detected, and/or other measurements provided by a detector. The computing system may access input data describing barriers, fractures, well bores, and/or other features of the region 101, including the types of tracers stored in the barriers 108. The computing system may include programs, scripts, and/or other types of computer instructions that generate output data based on the input data. The output data may include spatio-temporal descriptions of fluid flow patterns in the reservoir 105, which may identify paths of fluid flow in the reservoir 105, barrier breaches, fracture locations, fluid flow rates, and/or other information.

The well system 100 may be modified or adjusted based on the detection of tracers released from the barriers 108 into the reservoir 105. For example, well system tools, and/or other subsystems may be installed, adjusted, activated, terminated, or otherwise modified based on the information provided by the tracers. In some cases, fluid injection at the treatment well 104 can be modified, locations and characteristics of the barriers 108 can be modified, additional barriers can be formed in the reservoir 105, additional fractures can be formed in the reservoir 105, production tubing and packers in the production well 103 can be reconfigured, and/or other modifications can be made based on information provided by the tracers. In the present disclosure, the term “based on” indicates that an item or operation is based at least in part on one or more other items or operations—and may be based exclusively, partially, primarily, secondarily, directly, or indirectly on the one or more other items or operations. In some implementations, the modifications of the well system 100 are selected and/or parameterized to improve production from the reservoir 105. For example, the modifications may improve the sweep efficiency of the treatment fluids 110. In some implementations, the modifications of the well system 100 are selected and/or parameterized by the computing system based on data analysis performed by the computing system.

FIG. 2 is a diagram of an example well system 200 forming barriers 208 in a reservoir 205. The barriers 208 include sealant 226 and tracers 228. The sealant 226 may include materials that inhibit or reduce flow in the barrier 208. The sealant 226 may include materials that harden and/or become less viscous in the barrier 208.

In some implementations, the sealant used to provide the barrier may be any material capable of selectively or non-selectively reducing the flow of one or more fluids within a subterranean formation. A non-selective barrier substantially seals the fracture. A selective barrier modifies the permeability or relative permeability to allow fluids to selectively flow through the fracture. Example sealant materials include cements, linear polymer mixtures, linear polymer mixtures with a cross-linker, in-situ polymerized monomer mixtures, resin-based fluids, epoxy-based fluids, magnesium-based slurries, metallic particles, a clay based slurry (e.g., a bentonite based slurry), an emulsion, a precipitate (e.g., a polymeric precipitate), or an in-situ precipitate. An in-situ precipitate can be formed within the subterranean formation, for example, using a polymeric solution introduced into a subterranean formation followed by an activator.

A subterranean barrier may incorporate components with physical properties that aid remote geophysical measurement of the barrier geometry and/or the internal barrier structure. Such considerations can be useful for quality control, remedial intervention, and/or other tasks. In some implementations, the material composition of the barrier 208 is selected to make the barrier 208 more “visible” (i.e., detectable) by remote geophysical measuring devices. For example, some selected materials such as barite included in the barrier 208 may increase density contrast of the barrier 208 with the surrounding reservoir 205, thus making the barrier 208 more visible to seismic probing; other selected materials (e.g., metallic particles and/or others) included in the barrier may enhance the electromagnetic response from the barrier 208, making the response more distinguishable from the surrounding reservoir 205.

The sealant 226 can be injected in a fluid state and become viscous or solid in the reservoir 205. The viscous or solid sealant 226 in the reservoir can act as a barrier to fluid migration. An example sealant is H2ZERO™, an organically cross-linked polymer that can be used to fracture the reservoir and form a flow barrier in the resulting fracture. Other sealants may include particles, ground cuttings, drilling mud, cuttings, slag, and/or others. Drilling mud may include all types of drilling mud including oil based muds, invert emulsions, polymer based muds, clay based muds, weighted muds, and/or others. Sealants including a wide range of particle sizes may help produce low permeability in the barrier 208 as compared to the surrounding reservoir 205.

In some implementations, the sealant may include swellable particles. A swellable particle can swell upon contact with a fluid, for example, an aqueous fluid, an oil-based fluid, gas, and/or others. In some instances, swellable particles swell by up to 200% of their original size at the surface. Under downhole conditions, this swelling may be more, or less, depending on the conditions present. For example, the swelling may be at least 10% under downhole conditions. In some implementations, the swelling may be up to approximately 50% under downhole conditions. The rate of swelling may be seconds, minutes, hours, or days. An example of a swellable particle includes a swellable elastomer that swells in the presence of an oil-based fluid or an aqueous-based fluid. Swelling elastomers may be used to activate tracers, for example, by crushing a capsule when the elastomer expands upon contact with hydrocarbons or other fluids. Some specific examples of swellable elastomers that swell in the presence of an oil-based fluids include natural rubbers, acrylate butadiene rubbers, isoprene rubbers, chloroprene rubbers, butyl rubbers, brominated butyl rubbers, chlorinated butyl rubbers, chlorinated polyethylenes, neoprene rubbers, styrene butadiene copolymer rubbers, chlorinated polyethylene, sulphonated polyethylenes, ethylene acrylate rubbers, epichlorohydrin ethylene oxide copolymers, epichlorohydrin terpolymer, ethylene-propylene rubbers, ethylene vinyl acetate copolymers, ethylene-propylene-diene terpolymer rubbers, ethylene vinyl acetate copolymer, nitrile rubbers, acrylonitrile butadiene rubbers, hydrogenated acrylonitrile butadiene rubbers, carboxylated high-acrylonitrile butadiene copolymers, polyvinylchloride-nitrile butadiene blends, fluorosilicone rubbers, silicone rubbers, poly 2,2,1-bicyclo heptenes (polynorbornene), alkylstyrenes, polyacrylate rubbers such as ethylene-acrylate copolymer, ethylene-acrylate terpolymers, fluorocarbon polymers, copolymers of poly(vinylidene fluoride) and hexafluoropropylene, terpolymers of poly(vinylidene fluoride), hexafluoropropylene, and tetrafluoroethylene, terpolymers of poly(vinylidene fluoride), polyvinyl methyl ether and tetrafluoroethylene, perfluoroelastomers such as tetrafluoroethylene perfluoroelastomers, highly fluorinated elastomers, butadiene rubber, polychloroprene rubber, polyisoprene rubber, polynorbornenes, polysulfide rubbers, polyurethanes, silicone rubbers, vinyl silicone rubbers, fluoromethyl silicone rubber, fluorovinyl silicone rubbers, phenylmethyl silicone rubbers, styrene-butadiene rubbers, copolymers of isobutylene and isoprene known as butyl rubbers, brominated copolymers of isobutylene and isoprene, chlorinated copolymers of isobutylene and isoprene, and any combination thereof. An example of a commercially available product including such swellable particles may include a commercially available product from Easy Well Solutions, in Norway, under the trade name “EASYWELL.”

Examples of fluoroelastomers that swell in the presence of an oil-based fluid include copolymers of vinylidene fluoride and hexafluoropropylene and terpolymers of vinylidene fluoride, hexafluoropropylene and tetrafluoroethylene. Fluoroelastomers include elastomers that may have one or more vinylidene fluoride units (“VF2” or “VdF”), one or more hexafluoropropylene units (“HFP”), one or more tetrafluoroethylene units (“TFE”), one or more chlorotrifluoroethylene (“CTFE”) units, and/or one or more perfluoro(alkyl vinyl ether) units (“PAVE”), such as perfluoro(methyl vinyl ether) (“PMVE”), perfluoro(ethyl vinyl ether) (“PEVE”), and perfluoropropyl vinyl ether (“PPVE”). These elastomers can be homopolymers or copolymers. Some fluoroelastomers contain vinylidene fluoride units, hexafluoropropylene units, and, optionally, tetrafluoroethylene units and fluoroelastomers containing vinylidene fluoride units, perfluoroalkyl perfluorovinyl ether units, and tetrafluoroethylene units, such as the vinylidene fluoride type fluoroelastomer known under the trade designation “AFLAS®” available from Asahi Glass Co., Ltd. Copolymers may include vinylidene fluoride and hexafluoropropylene units may. If the fluoropolymers contain vinylidene fluoride units, the polymers may contain up to 40 mole % VF2 units, e.g., 30-40 mole %. If the fluoropolymers contain hexafluoropropylene units, the polymers may contain up to 70 mole % HFP units. If the fluoropolymers contain tetrafluoroethylene units, the polymers may contain up to 10 mole % TFE units. When the fluoropolymers contain chlorotrifluoroethylene the polymers may contain up to 10 mole % CTFE units. When the fluoropolymers contain perfluoro(methyl vinyl ether) units, the polymers may contain up to 5 mole % PMVE units. When the fluoropolymers contain perfluoro(ethyl vinyl ether) units, the polymers may contain up to 5 mole % PEVE units. When the fluoropolymers contain perfluoro(propyl vinyl ether) units, the polymers may contain up to 5 mole % PPVE units. The fluoropolymers may contain 66%-70% fluorine. An example commercially available fluoroelastomer is known under the trade designation “TECHNOFLON FOR HS®” sold by Ausimont USA. This material contains “Bisphenol AF” manufactured by Halocarbon Products Corp. Another commercially available fluoroelastomer is known under the trade name “VITON® AL 200,” by DuPont Dow Elastomers, which is a terpolymer of VF2, HFP, and TFE monomers containing 67% fluorine. Another suitable commercially available fluoroelastomer is “VITON® AL 300,” by DuPont Dow Elastomers. A blend of the terpolymers known under the trade designations “VITON® AL 300” and “VITON® AL 600” can also be used (e.g., one-third AL-600 and two-thirds AL-300); both are available from DuPont Dow Elastomers. Other useful elastomers include products known under the trade designations “7182B” and “7182D” from Seals Eastern, Red Bank, N.J.; the product known under the trade designation “FL80-4” available from Oil States Industries, Inc., Arlington, Tex.; and the product known under the trade designation “DMS005” available from Duromould, Ltd., Londonderry, Northern Ireland.

Techniques for making a swellable elastomer may involve grafting an unsaturated organic acid molecule. An example of an unsaturated organic acid used for this purpose is maleic acid. Other molecules that can be used include mono- and di-sodium salts of maleic acid and potassium salts of maleic acid. Although other unsaturated carboxylic acids may also be grafted onto commercial unsaturated elastomers, acids that exist in solid form may not require additional steps or manipulation. Mixing other unsaturated acids such as acrylic acid and methacrylic acid is also possible. Unsaturated acids such as palmitoleic acid, oleic acid, linoleic acid, and linolenic acid may also be used. The initial reaction leads to a relatively non-porous “acid-grafted rubber.” To enhance the swelling of elastomers, addition of a small amount of alkali such as soda ash, along with or separate from the unsaturated acid, may lead to formation of a porous, swellable acid grafted rubber. Micro-porosities may form in the composition, allowing a fluid to rapidly reach the interior region of a molded part and increase the rate and extent of swelling. An organic peroxide vulcanizing agent may be employed to produce a vulcanized, porous, swellable acid-grafted rubber formulation. In some implementations, 100 phr of EPDM, 5-100 phr of maleic acid, 5-50 phr of sodium carbonate, and 1-10 phr of dicumyl peroxide as vulcanizing agent showed at least 150 percent swelling of elastomer when exposed to both water at 100° C. for 24 hrs and at room temperature for 24 hrs in kerosene. Other commercially available grades of organic peroxides, as well as other vulcanization agents, may be used. The resulting elastomeric compositions may include non-porous or porous, swelled, acid-grafted rubbers, which may or may not be vulcanized. Vulcanization may refer to a physicochemical change resulting from crosslinking of the unsaturated hydrocarbon chain of polyisoprene with sulfur, usually with the application of heat. The relatively hydrophobic linear or branched chain polymers and relatively hydrophilic water-soluble monomers, either grafted onto the polymer backbone or blended therein, may act together to cost-effectively increase the water- and/or oil-swellability of oilfield elements. Use of unsaturated organic acids, anhydrides, and their salts (for example maleic acid, maleic anhydride, and theirs salts), may offer inexpensive composites materials with good water, and/or hydrocarbon fluid swellability, depending on the type of inorganic additives and monomers used.

Elastomers such as nitrile rubber, hydrogenated nitrile rubber (HNBR), fluoroelastomers, or acrylate-based elastomers, or their precursors, if added in variable amounts to an EPDM polymer or its precursor monomer mixture, along with a sufficient amount (from approximately 1 to 10 phr) of an unsaturated organic acid, anhydride, or salt thereof, such as maleic acid, optionally combined with a sufficient amount (from approximately 1 to 10 phr) an inorganic swelling agent such as sodium carbonate, may produce a water-swellable elastomer having variable low-oil swellability. Adding to the monomer mixture or to the elastomer after polymerization of a sufficient amount (from approximately 0.5 to 5 phr) of a highly acidic unsaturated compound such as 2-acrylamido-2-methylpropane sulfonic acid (AMPS), may result in a water-swellable elastomer having variable oil-swellability, and which may be further swellable in low pH fluids such as completion fluids containing zinc bromide. A second addition of a sufficient amount (from 1 to 10 phr more than the original addition) of inorganic swelling agent may enhance swellability in low pH, high concentration brines. Finally, the addition of a sufficient amount (from 1 to 20 phr) of zwitterionic polymer or copolymer of a zwitterionic monomer with an unsaturated monomer, may result in a cross-linked elastomer. The amounts of the various ingredients at each stage may be varied. For example, to produce a highly cross-linked, moderately water-swellable (approximately 100 percent swell) elastomer having very low oil-swellability but very high swellability in low pH fluids, a recipe of 60 to 80 phr of EPDM, and 20 to 40 phr of nitrile or HNBR, and 4 to 5 phr of AMPS, as well as approximately 15 to 20 phr of a zwitterionic polymer or monomer may be used.

Another reaction scheme that may enable a low-cost procedure for making swellable elastomers, involves the use of AMPS monomer and like sulfonic acid monomers. Since AMPS monomer is chemically stable up to at least 350° F. (177° C.), mixtures of EPDM and AMPS monomer which may or may not be grafted on to EPDM may function as a high-temperature resistant water-swellable elastomer. The use of AMPS and like monomers maybe used in like fashion to functionalize any commercial elastomer to make a high-temperature water-swellable elastomer. An advantage of using AMPS is that it is routinely used in oilfield industry in loss circulation fluids and is resistant to down hole chemicals and environments.

Other swellable elastomers behave in a similar fashion with respect to aqueous fluids. Some specific examples of suitable swellable elastomers that swell in the presence of an aqueous-based fluid, include starch-polyacrylate acid graft copolymer, polyvinyl alcohol cyclic acid anhydride graft copolymer, polyacrylamide, poly(acrylic acid-co-acrylamide), poly(2-hydroxyethyl methacrylate), poly(2-hydroxypropyl methacrylate), isobutylene maleic anhydride, acrylic acid type polymers, vinylacetate-acrylate copolymer, polyethylene oxide polymers, carboxymethyl cellulose type polymers, starch-polyacrylonitrile graft copolymers and the like, and highly swelling clay minerals such as sodium bentonite having montmorillonite as main ingredient, and combinations thereof.

Additional water swellable particles may include particulate matter embedded in a matrix material. One example of such particulate matter is salt, including dissociating salt, which can be uniformly compounded into a base rubber. Suitable salts may include acetates, bicarbonates, carbonates, formates, halides (MxHy) (H=Cl, Br or I), hydrosulphides, hydroxides, imides, nitrates, nitrides, nitrites, phosphates, sulphides, sulphates, and combinations thereof. Also, other salts can be applied wherein the cation is a non-metal like NH₄Cl. CaCl₂ may be useful in view of its divalent characteristic and because of its reduced tendency to leach out from a base rubber due to reduced mobility of the relatively large Ca atom in the base rubber.

To limit or control leaching out of the salt from the swellable elastomer, the swellable particles may include a hydrophilic polymer containing polar groups of either oxygen or nitrogen in the backbone or side groups of the polymer matrix material. These side groups can be partially or fully neutralized. Hydrophilic polymers of such type include, for example, alcohols, acrylates, methacrylates, acetates, aldehydes, ketones, sulfonates, anhydrides, maleic anhydrides, nitriles, acrylonitriles, amines, amides, oxides (polyethylene oxide), cellulose types including all derivatives of these types, all copolymers including one of the above all grafted variants. In some implementations, a ternary system may be applied which includes an elastomer, a polar SAP and a salt, whereby the polar SAP is grafted onto the backbone of the elastomer. Such system has the advantage that the polar SAP particles tend to retain the salt particles in the elastomer matrix thereby reducing leaching of the salt from the elastomer. The polar salt may be attracted by electrostatic forces to the polar SAP molecules which are grafted onto the backbone of the rubber.

Combinations of suitable swellable elastomers may also be used. In some implementations, some of the elastomers that swell in oil-based fluids may also swell in aqueous-based fluids. Elastomers that may swell in both aqueous-based and oil-based fluids, include ethylene propylene rubbers, ethylene-propylene-diene terpolymer rubbers, butyl rubbers, brominated butyl rubbers, chlorinated butyl rubbers, chlorinated polyethylene, neoprene rubbers, styrene butadiene copolymer rubbers, sulphonated polyethylenes, ethylene acrylate rubbers, epichlorohydrin ethylene oxide copolymer, silicone rubbers and fluorosilicone rubbers, and any combination thereof. Appropriate fluids may be used to swell the swellable elastomer compositions.

In some implementations, the swellable elastomers may be crosslinked and/or lightly crosslinked. Other swellable elastomers behave in a similar fashion with respect to fluids. Appropriate swellable elastomers may be selected based on a variety of factors, including the application in which the composition will be used and the desired swelling characteristics.

Swellable particles may be included in an amount sufficient to provide the desired barrier properties. In some implementations, the swellable particles may be placed in a fracture or void in a treatment fluid including an amount up to approximately 50% by volume of the treatment fluid. In some implementations, the swellable particles may be present in a range of approximately 5% to approximately 95% by volume of the treatment fluid used to place the particles.

In addition, the swellable particles that are utilized may have a wide variety of shapes and sizes of individual particles. For example, the swellable particles may have a well-defined physical shape as well as an irregular geometry, including the physical shape of platelets, shavings, fibers, flakes, ribbons, rods, strips, spheroids, beads, pellets, tablets, or any other physical shape. In some implementations, the swellable particles may have a particle size in the range of approximately 5 microns to approximately 1,500 microns. In some implementations, the swellable particles may have a particle size in the range of approximately 20 microns to approximately 500 microns. However, particle sizes outside these ranges may also be used.

The sealant may include a cement. An example of a cement includes hydraulic cement, which may include calcium, aluminum, silicon, oxygen, and/or sulfur and which sets and hardens by reaction with water. Examples of hydraulic cements include a Portland cement, a pozzolan cement, a gypsum cement, a high alumina content cement, a silica cement, a high alkalinity cement, or combinations thereof. Hydraulic cements include Portland cements, for example, a class A, B, C, G, or H Portland cement. Another example of a suitable cement is microfine cement, for example, MICRODUR RU microfine cement available from Dyckerhoff GmBH of Lengerich, Germany. Combinations of cements and swellable particles may also be used.

The sealant may include a water soluble relative permeability modifier. A relative permeability modifier may refer to a compound capable of reducing the permeability of a subterranean formation to aqueous-based fluids without substantially changing its permeability to hydrocarbons. In some implementations, the water-soluble relative permeability modifiers may include a hydrophobically modified polymer. “Hydrophobically modified” refers to the incorporation into the hydrophilic polymer structure of hydrophobic groups, wherein the alkyl chain length is from approximately 4 to approximately 22 carbons. In some implementations, the water-soluble relative permeability modifiers include a hydrophilically modified polymer. “Hydrophilically modified” refers to the incorporation into the hydrophilic polymer structure of hydrophilic groups. In some implementations, the water-soluble relative permeability modifiers include a water-soluble polymer without hydrophobic or hydrophilic modification.

Hydrophobically modified polymers typically have molecular weights in the range of from approximately 100,000 to approximately 10,000,000. In some implementations, a mole ratio of a hydrophilic monomer to the hydrophobic compound in the hydrophobically modified polymer is in the range of from approximately 99.98:0.02 to approximately 90:10, wherein the hydrophilic monomer is an amount present in the hydrophilic polymer. In some implementations, the hydrophobically modified polymers include a polymer backbone that include polar heteroatoms. The polar heteroatoms present within the polymer backbone of the hydrophobically modified polymers may include oxygen, nitrogen, sulfur, and/or phosphorous.

In some implementations, the hydrophobically modified polymers can be a reaction product of a hydrophilic polymer and a hydrophobic compound. The hydrophilic polymers for forming the hydrophobically modified polymers may be capable of reacting with hydrophobic compounds. Suitable hydrophilic polymers include, homo-, co-, or terpolymers, for example, polyacrylamides, polyvinylamines, poly(vinylamines/vinyl alcohols), and alkyl acrylate polymers in general. Additional examples of alkyl acrylate polymers include polydimethylaminoethyl methacrylate, polydimethylaminopropyl methacrylamide, poly(acrylamide/dimethylaminoethyl methacrylate), poly(methacrylic acid/dimethylaminoethyl methacrylate), poly(2-acrylamido-2-methyl propane sulfonic acid/dimethylaminoethyl methacrylate), poly(acrylamide/dimethylaminopropyl methacrylamide), poly(acrylic acid/dimethylaminopropyl methacrylamide), and poly(methacrylic acid/dimethylaminopropyl methacrylamide). In some implementations, the hydrophilic polymers include a polymer backbone and reactive amino groups in the polymer backbone or as pendant groups, the reactive amino groups capable of reacting with hydrophobic compounds. In some implementations, the hydrophilic polymers include dialkyl amino pendant groups. In some implementations, the hydrophilic polymers include a dimethyl amino pendant group and at least one monomer including dimethylaminoethyl methacrylate or dimethylaminopropyl methacrylamide. In some implementations, the hydrophilic polymers include a polymer backbone, the polymer backbone including polar heteroatoms, where the polar heteroatoms present within the polymer backbone of the hydrophilic polymers include oxygen, nitrogen, sulfur, and/or phosphorous. Suitable hydrophilic polymers that include polar heteroatoms within the polymer backbone include homo-, co-, or terpolymers, for example, celluloses, chitosans, polyamides, polyetheramines, polyethyleneimines, polyhydroxyetheramines, polylysines, polysulfones, gums, starches, and derivatives thereof. In some implementations, the starch is a cationic starch. A suitable cationic starch may be formed by reacting a starch, such as corn, maize, waxy maize, potato, and tapioca, and the like, with the reaction product of epichlorohydrin and trialkylamine.

Hydrophobic compounds capable of reacting with the hydrophilic polymers include alkyl halides, sulfonates, sulfates, and organic acid derivatives. Examples of suitable organic acid derivatives include octenyl succinic acid; dodecenyl succinic acid; and anhydrides, esters, and amides of octenyl succinic acid or dodecenyl succinic acid. In some implementations, the hydrophobic compounds may have an alkyl chain length of from approximately 4 to approximately 22 carbons. For example, where the hydrophobic compound is an alkyl halide, the reaction between the hydrophobic compound and hydrophilic polymer may result in the quaternization of at least some of the hydrophilic polymer amino groups with an alkyl halide, where the alkyl chain length is from approximately 4 to approximately 22 carbons.

In some implementations, hydrophobically modified polymers may be prepared from the polymerization reaction of at least one hydrophilic monomer and at least one hydrophobically modified hydrophilic monomer.

A variety of hydrophilic monomers may be used to form hydrophobically modified polymers. Examples of suitable hydrophilic monomers include homo-, co-, and terpolymers of acrylamide, 2-acrylamido-2-methyl propane sulfonic acid, N,N-dimethylacrylamide, vinyl pyrrolidone, dimethylaminoethyl methacrylate, acrylic acid, dimethylaminopropylmethacrylamide, vinyl amine, vinyl acetate, trimethylammoniumethyl methacrylate chloride, methacrylamide, hydroxyethyl acrylate, vinyl sulfonic acid, vinyl phosphonic acid, methacrylic acid, vinyl caprolactam, N-vinylformamide, N,N-diallylacetamide, dimethyldiallyl ammonium halide, itaconic acid, styrene sulfonic acid, methacrylamidoethyltrimethyl ammonium halide, quaternary salt derivatives of acrylamide, and quaternary salt derivatives of acrylic acid.

A variety of hydrophobically modified hydrophilic monomers also may be used to form hydrophobically modified polymers. Examples of suitable hydrophobically modified hydrophilic monomers include alkyl acrylates, alkyl methacrylates, alkyl acrylamides, alkyl methacrylamides alkyl dimethylammoniumethyl methacrylate halides, and alkyl dimethylammoniumpropyl methacrylamide halides, wherein the alkyl groups have from approximately 4 to approximately 22 carbon atoms. In some implementations, the hydrophobic ally modified hydrophilic monomer includes octadecyldimethylammoniumethyl methacrylate bromide, hexadecyldimethylammoniumethyl methacrylate bromide, hexadecyldimethylammoniumpropyl methacrylamide bromide, 2-ethylhexyl methacrylate, or hexadecyl methacrylamide.

The hydrophobically modified polymers formed from the above-described polymerization reaction may have estimated molecular weights in the range of from approximately 100,000 to approximately 10,000,000 and mole ratios of the hydrophilic monomer(s) to the hydrophobically modified hydrophilic monomer(s) in the range of from approximately 99.98:0.02 to approximately 90:10. Hydrophobically modified polymers having molecular weights and mole ratios in the ranges set forth above include acrylamide/octadecyldimethylammoniumethyl methacrylate bromide copolymer, dimethylaminoethyl methacrylate/hexadecyldimethylammoniumethyl methacrylate bromide copolymer, dimethylaminoethyl methacrylate/vinyl pyrrolidone/hexadecyldimethylammoniumethyl methacrylate bromide terpolymer and acrylamide/2-acrylamido-2-methyl propane sulfonic acid/2-ethylhexyl methacrylate terpolymer.

In some implementations, the water-soluble relative permeability modifiers include a hydrophilically modified polymer. Hydrophilically modified polymers typically have molecular weights in the range of from approximately 100,000 to approximately 10,000,000. In some implementations, the hydrophilically modified polymers include a polymer backbone, the polymer backbone including polar heteroatoms. The polar heteroatoms present within the polymer backbone of the hydrophilically modified polymers may include oxygen, nitrogen, sulfur, and/or phosphorous.

In some implementations, a hydrophilically modified polymer may be a reaction product of a hydrophilic polymer and a hydrophilic compound. Hydrophilic polymers suitable for forming hydrophilically modified polymers may be capable of reacting with hydrophilic compounds. In some implementations, hydrophilic polymers include homo-, co-, or terpolymers, for example, polyacrylamides, polyvinylamines, poly(vinylamines/vinyl alcohols), and alkyl acrylate polymers in general. Additional examples of alkyl acrylate polymers include polydimethylaminoethyl methacrylate, polydimethylaminopropyl methacrylamide, poly(acrylamide/dimethylamino ethyl methacrylate), poly(methacrylic acid/dimethylaminoethyl methacrylate), poly(2-acrylamido-2-methyl propane sulfonic acid/dimethylaminoethyl methacrylate), poly(acrylamide/dimethylaminopropyl methacrylamide), poly (acrylic acid/dimethylaminopropyl methacrylamide), and poly(methacrylic acid/dimethylaminopropyl methacrylamide). In some implementations, the hydrophilic polymers include a polymer backbone and reactive amino groups in the polymer backbone or as pendant groups, the reactive amino groups capable of reacting with hydrophilic compounds. In some implementations, the hydrophilic polymers include dialkyl amino pendant groups. In some implementations, the hydrophilic polymers include a dimethyl amino pendant group and at least one monomer including dimethylaminoethyl methacrylate or dimethylaminopropyl methacrylamide. In some implementations, the hydrophilic polymers include a polymer backbone including polar heteroatoms, wherein the polar heteroatoms present within the polymer backbone of the hydrophilic polymers include oxygen, nitrogen, sulfur, and/or phosphorous. Suitable hydrophilic polymers that include polar heteroatoms within the polymer backbone include homo-, co-, or terpolymers, such as celluloses, chitosans, polyamides, polyetheramines, polyethyleneimines, polyhydroxyetheramines, polylysines, polysulfones, gums, starches, and derivatives thereof. In some implementations, the starch is a cationic starch. A suitable cationic starch may be formed by reacting a starch, such as corn, maize, waxy maize, potato, tapioca, and the like, with the reaction product of epichlorohydrin and trialkylamine.

Hydrophilic compounds suitable for reaction with the hydrophilic polymers include polyethers that include halogens; sulfonates; sulfates; and organic acid derivatives. Examples of suitable polyethers include polyethylene oxides, polypropylene oxides, and polybutylene oxides, and copolymers, terpolymers, and mixtures thereof. In some implementations, the polyether includes an epichlorohydrin-terminated polyethylene oxide methyl ether.

Hydrophilically modified polymers formed from the reaction of a hydrophilic polymer with a hydrophilic compound may have estimated molecular weights in the range of from approximately 100,000 to approximately 10,000,000 and may have weight ratios of the hydrophilic polymers to the polyethers in the range of from approximately 1:1 to approximately 10:1. Hydrophilically modified polymers having molecular weights and weight ratios in the ranges set forth above include the reaction product of polydimethylaminoethyl methacrylate and epichlorohydrin-terminated polyethyleneoxide methyl ether; the reaction product of polydimethylaminopropyl methacrylamide and epichlorohydrin-terminated polyethyleneoxide methyl ether; and the reaction product of poly(acrylamide/dimethylaminopropyl methacrylamide) and epichlorohydrin-terminated polyethyleneoxide methyl ether. In some implementations, the hydrophilically modified polymer includes the reaction product of a polydimethylaminoethyl methacrylate and epichlorohydrin-terminated polyethyleneoxide methyl ether having a weight ratio of polydimethylaminoethyl methacrylate to epichlorohydrin-terminated polyethyleneoxide methyl ether of approximately 3:1.

In some implementations, the water-soluble relative permeability modifiers include a water-soluble polymer without hydrophobic or hydrophilic modification. Examples of suitable water-soluble polymers without hydrophobic or hydrophilic modification include homo-, co-, and terpolymers of acrylamide, 2-acrylamido-2-methyl propane sulfonic acid, N,N-dimethylacrylamide, vinyl pyrrolidone, dimethylaminoethyl methacrylate, acrylic acid, dimethylaminopropylmethacrylamide, vinyl amine, vinyl acetate, trimethylammoniumethyl methacrylate chloride, methacrylamide, hydroxyethyl acrylate, vinyl sulfonic acid, vinyl phosphonic acid, methacrylic acid, vinyl caprolactam, N-vinylformamide, N,N-diallylacetamide, dimethyldiallyl ammonium halide, itaconic acid, styrene sulfonic acid, methacrylamidoethyltrimethyl ammonium halide, quaternary salt derivatives of acrylamide, and quaternary salt derivatives of acrylic acid.

The tracers 228 may include material that can be transported from the barrier 208 and detected. The tracers 228 may include material that is not naturally present in the reservoir 205 (at least, not naturally present in quantities that exceed the detection threshold of tracer detection instruments) that can be transported by means of fluid migration and detected by well-based or surface-based instrumentation. The tracers 228 may include chemical tracers, radioactive tracers, noble gas tracers, micro- and nano-devices, water soluble tracers, hydrocarbon soluble tracers, other types of tracers, and/or combinations of these. Chemical tracers include substances that can be detected based on chemical properties (e.g., pH, resistivity, etc.) of fluids containing the tracer. Example chemical tracers include alcohols, salts, acids, and others. Radioactive tracers include substances that can be detected based on properties of radioactivity (e.g., frequency, intensity of gamma rays emitted, and/or others) in the subterranean region 201. Radioactive tracers may be chosen, for example, based on their half-life and/or other properties. Example radioactive tracers include radioactive nuclei having half lives ranging from 1 day to 500 days, including antimony 124, iridium 192, scandium 46, gold 198, iodine 131, zinc 65, silver 100, cobalt 57, and others. Noble gas tracers include noble gases, for example, helium, neon, argon, krypton, and xenon. Micro- and nano-device tracers may include manufactured radio frequency devices, microelectromechanical (MEMS) devices, metal-oxide-semiconductor (MOS) devices, and/or similar devices. Tracer devices may function as passive or active radio frequency emitting devices that can be detected by a radio frequency detector. Tracers may include fluorinated benzoic acid. Tracer devices may be used to detect and record properties of fluid flow. For example, tracer devices may detect and record phase composition, flow velocity, location, and/or other data. Other example tracers include dyes, such as flourescein dyes, oil soluble dyes, and oil dispersible dyes; organic materials, such as guar, sugars, glycerol, surfactants, scale inhibitors, etc.; phosphorescent pigments; fluorescent pigments; photoluminescent pigments; oil dispersible pigments; metals; and/or others.

The tracers 228 can be selected for use in the system 200 based on their interaction or reaction to fluids in the reservoir 205. Some tracers can be released from the barrier 208 when contacted by certain types of fluid. For example, a tracer that dissolves in the treatment fluid that is used to sweep the reservoir 205 may be selected; or a tracer that dissolves in hydrocarbons resident in the reservoir 205 may be selected. A water-soluble tracer dissolves in water, and a hydrocarbon-soluble tracer dissolves in hydrocarbon. A tracer may have a coating that dissolves in certain types of fluids to release the tracer. For example, the tracer may have a water-soluble or hydrocarbon-soluble coating. A tracer may be stress activated. For example, a tracer may be injected with a coating that is crushed by a certain amount of stress, and the tracer may be released into the reservoir 205 after the coating has been crushed under stress in the barrier 208.

The well system 200 includes an injection system 211 that injects the sealant mixture into the reservoir 205. The injection system 211 can be used to create the barriers 108 of FIG. 1, the barriers 208 of FIG. 2, the barriers 408 of FIG. 4, the barriers 508a and 508b of FIG. 5, and/or other barriers. In some implementations, an injection system is used to create fractures in the subterranean reservoir, for example, the fracture 106 of FIG. 1, the fractures 206 of FIG. 2, the fractures 406 of FIG. 4, the fractures 506 of FIG. 5, and/or other fractures. The injection system 211 includes pump trucks 221, instrument trucks 222, working string 220, flow control device 223, packers 224, and other equipment. The injection system 211 may include features of the injection system 330 shown in FIG. 3 and/or other features.

The pump trucks 221 may include mobile vehicles, immobile installations, skids, hoses, tubes, fluid tanks or reservoirs, pumps, valves, and/or other suitable structures and equipment. The pump trucks 221 supply sealant material 226 and tracers 228. The pump trucks 221 may contain multiple different sealant materials, multiple different tracers, and/or multiple different sealant/tracer mixtures. The pump trucks may include mixers that mix the sealant 226 and tracers 228.

The pump trucks 221 are coupled to the working string 220 to communicate the sealant material 226, the tracers 228, and/or a mixture containing the sealant material 226 and tracers 228 into the well bore 203. The working string 220 may include coiled tubing, sectioned pipe, and/or other features that communicate fluid through the well bore 203. The working string 220 is coupled to the flow control device 223. The flow control device 223 may include a valve, a sliding sleeve, a port, and/or other features that communicate fluid from the working string 220 into the reservoir 205. The flow control device 223 may include a fracturing tool. Example fracturing tools include hydrajetting tools, such as the SURGIFRAC tool (manufactured by HALLIBURTON), the COBRA FRAC tool (manufactured by HALLIBURTON), and others. The barriers 208 may be formed without use of a flow control device 223. For example, fluids may be injected by an open end of the working string 220 without using a flow control device 223. The packers 224 reside in an annulus between the working string 220 and the well bore wall (or casing, where the well bore 203 is cased). The packers 224 isolate an interval of the reservoir 205 that receives the injected materials from the flow control device 223. The packers 224 may include mechanical packers, fluid inflatable packers, sand packers, and/or other types of packers.

The instrument trucks 222 may include mobile vehicles, immobile installations, and/or other suitable structures. The instrument trucks 222 control and/or monitor the injection treatment. For example, the instrument trucks 222 may include communication links 225 that allow the instrument trucks 222 to communicate with tools, sensors, and/or other devices installed in the well bore 203; the instrument trucks 222 may include communication links 225 that allow the instrument trucks 222 to communicate with the pump trucks 221 and/or other systems at the surface 202. The instrument trucks 222 may include an injection control system that controls the flow of sealant and tracer materials into the reservoir 205 to achieve barriers 208 having desired properties. For example, the instrument trucks 222 may monitor and/or control the density, volume, flow rate, flow pressure, location, and/or other characteristics of the tracers 228 and/or the sealant 226 injected into the reservoir 205. The instrument trucks 222 may control the type of tracer injected into each of the barriers 208 and/or the type of tracer injected into different parts of each barrier 208. In the present disclosure, “each” refers to each of multiple items or operations in a group, and may include a subset of the items or operations in the group and/or all of the items or operations in the group.

The injection system 211 may also include surface and down-hole sensors (not shown) to measure pressure, rate, temperature and/or other parameters of treatment and/or production. The injection system 211 may include pump controls and/or other types of controls for starting, stopping and/or otherwise controlling pumping as well as controls for selecting and/or otherwise controlling fluids pumped during the injection treatment. An injection control system (e.g., in the instrument trucks 222) may communicate with such equipment to monitor and control the injection treatment.

In one aspect of operation, the pump trucks 221 pump the tracers 228 and the sealant material 226 down the well bore 203 through the working string 220. From the working string 220, the tracers 228 and sealant material 226 are received by the flow control device 223 and injected into the reservoir 205. After the tracers 228 and sealant material 226 have been injected, the sealant material 226 may become more viscous and/or solidify in the reservoir 205. The sealant 226 may impede or prevent fluid flow in the resulting barrier 208, which may alter fluid flow patterns in the reservoir 205. The sealant mixture may be injected into the reservoir 205 at a high pressure to fracture the reservoir during the injection. The sealant mixture may be injected into the reservoir 205 at a low pressure to fill an existing fracture. The pressure may be controlled in a different manner to achieve a desired result. The sealant mixture, which includes the tracers 228 and sealant material 226, may be mixed prior to injection, for example, in the pump trucks 221, in the working string 220, in the flow control device 223, in a different location, and/or in a combination of these. The sealant mixture may be fully or partially mixed when the tracers 228 and sealant 226 are injected into the reservoir 205. The sealant 226 and tracers 228 may remain separate from each other until they are combined in the reservoir 205, in the annulus, in the flow control device 223, in the working string 220, in the pump trucks 221, and/or at any stage of forming the barrier 208.

Additional barriers may be formed in the reservoir 205 using the injection system 211. For example, the barriers 208 and/or additional barriers can be placed as a remedial treatment after the well has been producing for some time. As such, barriers can be emplaced and/or modified at different times over the production lifetime of the well system 200. Flow control devices 223 and packers 224 may be positioned at different locations in the well bore 203 to create additional barriers in the reservoir 205.

FIG. 3 is a diagram of an example treatment well 300 that includes an injection system 330 injecting treatment fluid into a subterranean reservoir 305 in a subterranean region 301. The injection system 330 may be used with the treatment well 104 of FIG. 1 to inject the treatment fluid 110 into the subterranean reservoir 105. In some implementations, the injection system 330 injects treatment fluids 310 into a reservoir to displace or sweep resident hydrocarbon resources through the reservoir to a production well. A barrier in the reservoir may influence the flow of the treatment fluids 310 and/or the displaced hydrocarbons through the reservoir. In some cases, a barrier releases a tracer into the reservoir when the barrier is contacted by the treatment fluids 310 and/or the hydrocarbons. Movement of the tracer in the reservoir may be detected and analyzed to identify flow patterns in the reservoir.

The example treatment well 300 shown in FIG. 3 includes a well bore 304 with a casing 334 cemented or otherwise secured to the well bore wall. A treatment well may include an uncased well bore. Perforations 336 may be formed in the casing 334 to allow treatment fluids 310 and/or other materials to flow into the reservoir 305. Perforations 336 may be formed using shape charges, a perforating gun, and/or other tools.

The injection system 330 includes pump trucks 321, instrument trucks 322, working string 332, flow control device 338, packers 324, and other equipment. The injection system 330 may include features of the injection system 211 shown in FIG. 2 and/or other features. The pump trucks contain treatment fluid 310 to be injected into the reservoir 305. The treatment fluid 310 may include water, steam, and/or other types of compressible and/or incompressible fluids that can promote migration of hydrocarbons through the reservoir 305. The pump trucks 321 are coupled to the working string 332 to communicate treatment fluid 310 into the well bore 304. The working string 332 is coupled to the flow control device 338, which communicates fluid from the working string 332 into the reservoir 305. Treatment fluid 310 may be injected without use of a flow control device 338. For example, fluids may be injected by an open end of the working string 332 without using a flow control device 338. The packers 324 reside in an annulus between the working string 332 and the casing 334, and isolate an interval of the reservoir 305 that receives the treatment fluid 310 through the perforations 336.

The instrument trucks 322 control and/or monitor the injection treatment. For example, the instrument trucks 322 may include communication links 325 that allow the instrument trucks 322 to communicate with tools, sensors, and/or other devices installed in the well bore 304; the instrument trucks 322 may include communication links 325 that allow the instrument trucks 322 to communicate with the pump trucks 321 and/or other systems at the surface. The instrument trucks 322 may include an injection control system that control the flow of treatment fluid into the reservoir 305 to achieve a desired reservoir sweep. For example, the instrument trucks 322 may monitor and/or control the density, volume, flow rate, flow pressure, location, and/or other characteristics of the treatment fluid 310 injected into the reservoir 305.

In one aspect of operation, the pump trucks 321 pump the treatment fluid 310 down the well bore 304 through the working string 332. From the working string 332, the treatment fluid 310 flows through the flow control device 338, through the perforations 336, and into the reservoir 305. The treatment fluid 310 may form a fluid front in the reservoir 305. The fluid front may sweep through the reservoir 305 to displace hydrocarbons toward a production well. The treatment fluid 310 may contact a barrier in the reservoir 305 and cause the barrier to release tracers. The tracers may flow through the reservoir 305 with the treatment fluid 310 and/or other fluids. In some cases, the flow of the treatment fluid 310 through the reservoir may be analyzed based on the detection of the tracers' movement through the reservoir 305. The injection of the treatment fluid 310 may be modified based on the analysis. For example, the location, pressure, flow rate, fluid composition, and/or other parameters of the injection treatment may be modified to improve sweep efficiency.

FIG. 4 is a diagram of an example production well system 400 detecting tracers 428a (circles), 428b (triangles) released into a reservoir 405 from barriers 408. The production well system 400 includes a well bore 403 in a subterranean region 401 beneath the surface 404. The subterranean region 401 includes the reservoir 405, which includes fractures 406 and barriers 408. The fractures 406 conduct fluids from the reservoir 405 into the well bore 403. A completion string 420 installed in the well bore communicates the fluids to the surface 404.

The well system 400 includes tracer detectors 442a and 442b installed in the well bore 403, and a tracer detector 444 installed at the surface 404. In some cases, tracer detectors may be installed in additional, fewer, and/or different locations. For example, the well system 400 may be implemented without down hole tracer detectors 442a, 442b, without tracer detectors 444 at the surface, and/or with tracer detectors installed at different locations in the subterranean region 401. The tracer detectors 442a, 442b, and 444 may communicate with a computing subsystem 445 that stores and analyzes data generated by the tracer detectors. For example, the computing subsystem 445 may identify properties of fluid flow in the subterranean reservoir 405 based on data provided by the tracer detectors 442a, 442b, and/or 444.

The tracer detectors 442a, 442b, and 444 may each be adapted to detect one or more of the tracers 428a, 428b stored in the barriers 408. For example, the detectors may be adapted to detect chemical tracers, radioactive tracers, noble gas tracers, micro- and nano-device tracers, other types of tracers, and/or combinations of these. One or more of the detectors 442a, 442b, and 444 may detect chemical tracers by measuring chemical properties (e.g., pH, resistivity, etc.) of fluids received by the detectors. For example, a chemical tracer detector may include a pH sensor to monitor a pH level of fluids in the reservoir 405, which may detect an acid tracer. A chemical tracer detector may include an ohmmeter, an ammeter, a voltmeter, or another device to monitor a resistivity of fluids in the reservoir 405, which may detect a salt tracer, for example. One or more of the detectors 442a, 442b, and 444 may detect radioactive tracers based on radioactive properties (e.g., frequency, intensity of gamma rays emitted, and/or others) of material near the detector. For example, a radioactive tracer detector may include a scintillation crystal, a Geiger counter, or another device that detects radiation emitted by nuclear decay. One or more of the detectors 442a, 442b, and 444 may detect noble gas tracers based on properties of fluids received by the detector. For example, the detector may include sensor that detects helium, neon, argon, krypton, xenon, and/or related gasses.

One or more of the detectors 442a, 442b, and 444 may detect micro- and nano-device tracers. For example, the detectors may include an active radio frequency beacon that interrogates a zone around the detector for rf-device tracers. Rf-device tracers in the interrogated zone may reflect and/or scatter the radio frequency signal, and the detector may receive the reflected or scattered signal. For example, the detectors may include an antenna that receives reflected signals from the rf-device tracers. The detector may monitor the movement of rf-device tracers through the reservoir 405. In some cases, a micro- or nano-tracer device may include an active transmitter that transmits radio frequency signals that can be detected by one or more of the detectors.

Tracer devices may be used to detect and record properties of fluid flow. For example, tracer devices may detect and record phase composition, flow velocity, location, and/or other data. One or more of the detectors 442a, 442b, and 444 may receive the information from the tracer devices. One or more of the detectors 442a, 442b, and 444 may include sensors and/or other features that detect other example tracers, including dyes, organic materials, pigments, metals, and/or others.

Each of the barriers 408 includes a sealant material 426 and stores two different tracers 428a, 428b. The sealant material 426 is a low permeability material that inhibits fluid flow through the barriers 408. In the example shown in FIG. 4, the tracers 428a, 428b are each stored in different portions of the barriers 408. A first type of tracer 428a is stored in a portion of the barrier 408 farthest from the well bore 403; a second type of tracer 428b is stored in a portion of the barrier 408 closest to the well bore 403. In some implementations, the different tracers can be intermingled in the barrier rather than being stored in separate portions of the barrier.

The flow arrows 445, 446, and 448 show examples of fluid flow in the subterranean region 401. The flow arrows 445 indicate a flow of fluids that contact the barriers 408. In the example shown, the barriers 408 divert the flow of fluids away from the well bore 403. The fluids represented by the flow arrows 445 may include treatment fluids injected into the reservoir through a treatment well, other types of injected fluids, hydrocarbons, and/or other types of fluids native to the reservoir 405. The fluids represented by the flow arrows 445 do not include tracer materials before contacting the barriers 408.

As the fluids contact the barriers 408, the barriers release tracers 428a into the reservoir 405. Generally, any of the tracers in a barrier may be released into the reservoir based on contact and/or interaction with fluids in the reservoir. However, in some implementations, only certain tracers are released. For example, some tracers may only be released into the reservoir when contacted by the treatment fluids, some tracers may only be released into the reservoir when contacted by the hydrocarbon fluids, some tracers may only be released after a specified amount of time, some tracers may only be released when fluid contacts a certain portion of the barriers 408, etc. In the example shown in FIG. 4, only one of the tracers 428a is released into the reservoir 405, and the second tracer 428b is not released into the reservoir 405 due to contact with the fluids represented by the flow arrow 445. In some instances, the second tracer 428b may alternatively or additionally be released into the reservoir 405 due to contact with the fluids represented by the flow arrow 445.

The flow arrows 446 indicate a flow path of fluids containing tracers 428a that have been released by the barriers 408. In the example shown, the fluids represented by the flow arrows 446 have been diverted by barriers 408; the fluids transport the tracers 428a through the reservoir 405 into the fractures 406. The fractures 406 conduct the fluids and the tracers 428a into the well bore 403. In the well bore 403, the tracers 428a may be detected by either of the detectors 442a and 442b. The flow arrow 448 indicates a flow path of fluids and tracers 428a through the completion string 420 to the surface 404. At the surface, the tracers 428a may be detected by the detector 444.

FIG. 5 is a diagram of an example production well system 500 detecting tracers 528a (circles), 528b (triangles) released into a reservoir 505 from barriers 508a, 508b. The production well system 500 includes a well bore 503 in a subterranean region 501 beneath the surface 504. The subterranean region includes a reservoir 505, which includes fractures 506 and the barriers 508a, 508b. The fractures 506 conduct fluids from the reservoir 505 into the well bore 503. A completion string 520 installed in the well bore communicates the fluids to the surface 504.

The well system 500 includes tracer detectors 542a and 542b installed in the well bore 503, and a tracer detector 544 installed at the surface 504. Each of the barriers 508a, 508b includes a sealant material 526 and a tracer. The barriers 508a include a first tracer 528a, and the barriers 508b include a second tracer 528b. The flow arrows 545, 546, 547, and 548 show an example of fluid flow in the subterranean region 501. The flow arrows 545 indicate a flow path of fluids that contact the barriers 508b. The barrier 508b divert the flow of fluids away from the well bore 503. The fluids represented by the flow arrows 545 may include treatment fluids injected into the reservoir through a treatment well, other types of injected fluids, hydrocarbons, and/or other types of fluids native to the reservoir 505. The fluids represented by the flow arrows 545 do not include tracer materials before contacting the barriers 508b.

As the fluids contact the barriers 508b, the barriers 508b release tracers 528b into the reservoir 505. The flow arrows 546 indicate a flow path of fluids containing tracers 528b that have been released by the barriers 508b. As the fluids subsequently contact the barriers 508a, the barriers 508a release tracers 528a into the reservoir 505. The flow arrows 547 indicate a flow path of fluids containing tracers 528a and 528b that have been released by the barriers 508a and 508b. In the example shown, the fluids represented by the flow arrows 547 have been diverted by barriers 508a, 508b; the fluids transport the tracers 528a, 528b through the reservoir 505 into the fractures 506. The fractures 506 conduct the fluids and the tracers 528a, 528b into the well bore 503. In the well bore 503, the tracers 528a, 528b may be detected by either of the detectors 542a and 542b. The flow arrow 548 indicates a flow path of fluids and tracers 528a, 528b through the completion string 520 to the surface 504. At the surface, the tracers 528a, 528b may be detected by the detector 544.

One or more of the tracer detectors 542a, 542b, and 544 may communicate with a computing subsystem 545 that stores and analyzes data generated by the tracer detectors. For example, the computing subsystem 545 may identify properties of fluid flow in the subterranean reservoir 505 based on data provided by the tracer detectors 542a, 542b, and/or 544.

FIG. 6 is a flow chart showing an example process 600 for analyzing fluid flow in a reservoir. All or part of the example process 600 may be implemented using the features and attributes of the example well systems shown in FIGS. 1, 2, 3, 4, and 5. In some cases, aspects of the example process 600 may be performed in a single-well system, a multi-well system, a well system including multiple interconnected well bores, and/or in another type of well system, which may include any suitable well bore orientations. In some implementations, the example process 600 is implemented to analyze fluid flow in a hydrocarbon reservoir. The process 600 may be implemented after the reservoir has been produced for days, weeks, months, or years, or before the reservoir has produced resources. In some cases, the process 600 is implemented during a remedial production process that sweeps residual hydrocarbons from a reservoir that has been producing for some time. The process 600, individual operations of the process 600, and/or groups of operations may be iterated to achieve a desired result. In some cases, the process 600 may include the same, additional, fewer, and/or different operations performed in the same or a different order.

At 604, a sealant and a tracer are injected into a subterranean reservoir to form a flow barrier in the reservoir. The sealant and tracer may be injected into the reservoir through a well bore in the reservoir. The sealant and tracer may be mixed to form a sealant mixture before injection, during injection, and/or after injection. Injecting the sealant mixture may fracture the reservoir to form the flow barrier. The sealant mixture may be injected into existing fractures. The sealant in the reservoir may inhibit or reduce fluid flow in the flow barrier. In some cases, forming the flow barrier in the reservoir modifies fluid flow paths in the reservoir. For example, the flow barrier may divert flow in one or more directions. Multiple tracers may be injected. For example, a flow barrier may include multiple different types of tracers and/or multiple different flow barriers may each include a different type of tracer. In some cases, each of the multiple tracers are stored in different portions of the flow barrier; in some cases, each of the multiple tracers are stored together in the same portion of the flow barrier.

The tracer may be stored in the flow barrier. For example, the tracer may reside in the flow barrier for hours, days, weeks, months, or years. The tracer may include a chemical tracer, a radioactive tracer, a noble gas tracer, a radio frequency device tracer, a water-soluble tracer, a hydrocarbon-soluble tracer, a dye, a pigment, a metal, other types of tracers, and/or a combination of these.

In some implementations, multiple flow barriers are formed in the subterranean region and/or multiple tracers are stored in one or more of the barriers. Each barrier may store multiple different types of tracers, each tracer can be released into the reservoir based on a different condition. For example, each barrier can store a water-soluble tracer and a hydrocarbon-soluble tracer. As another example, each barrier can store a short half-life radioactive tracer and a long half-life radioactive tracer. The combination of tracers can be used to glean more information from the reservoir.

At 606, treatment fluid is injected into the reservoir. The treatment fluid may be injected through a well bore to displace or sweep hydrocarbons toward a production well. The treatment fluid may be injected through a different well than the production well used to form the flow barriers. The treatment fluid may include compressible fluids such as steam, non-compressible fluids such as water, heated treatment fluids, and/or other types of treatment fluids that can induce movement of hydrocarbons through the reservoir. The treatment fluids and/or the hydrocarbons displaced by the treatment fluids may contact or otherwise interact with the flow barrier in the subterranean reservoir. The contact or other interaction between the flow barrier and fluids in the reservoir may cause the tracer to be displaced from the barrier in the reservoir. The tracer may be displaced to a production well and/or to another part of the reservoir.

At 608, the tracer is detected outside of the barrier. The tracer may be detected in fluids received into a well bore. The tracer may be detected in fluids residing in the reservoir. A tracer detector may detect movement of the tracer. The detector may be installed in a well bore in the reservoir, at a ground surface above the reservoir, and/or at another location to monitor movement of tracers in the reservoir. The detector may detect the tracer based on radio frequency signals scattered by the tracers. The detector may detect the tracer based on monitoring the pH, resistivity, and/or other properties of fluids in the reservoir. The detector may detect the tracer based on radioactivity of the tracers (e.g., emission of alpha, beta, and/or gamma rays). The detector may detect the tracer based on detecting a noble gas in fluids in the reservoir. The detector may detect the tracer based on other types of measurements. Down hole tracer logs may indicate a location where tracers, and hence certain types of fluids (e.g., treatment fluid) enters the well bore.

At 610, fluid flow patterns in the reservoir are analyzed based on the detection of the tracer. For example, detecting the tracer in hydrocarbons produced into a well bore may indicate that the hydrocarbons contacted the barrier; detecting the tracer in treatment fluid produced into a well bore may indicate that the treatment fluid contacted the barrier. Based on the time and location where the tracer is detected, properties of macroscopic flow patterns in the reservoir may be identified.

In some implementations of the process 600, modifications to the reservoir can be made based on the information provided by detection of the tracer. Analysis may identify a breach in a flow barrier, and the flow barrier can subsequently be reinforced or supplemented to patch the breach. Analysis may identify a low permeability zone, and fractures and/or additional flow barriers may be formed in the reservoir to promote flow in the low permeability zone. Other modifications may also be made, as appropriate.

In some implementations of the process 600, modifications to an injection treatment can be made based on information provided by the detection of the tracer. Analysis may identify directions, locations, rates and/or other properties of fluid flow in the reservoir. An injection treatment may be designed and/or modified based on the information on fluid flow in the reservoir. For example, designing and/or modifying an injection treatment may involve selecting a location to inject treatment fluid, selecting a volume of treatment fluid to inject, and/or selecting other injection parameters. The injection treatment may be designed and/or modified to improve recovery of hydrocarbons from the reservoir.

FIGS. 7A-7C are diagrams of subterranean reservoir properties from an example numerical simulation of an injection treatment. The numerical simulation was performed by a data processing apparatus based on a model of a subterranean reservoir 705. The diagrams in FIGS. 7A-7D show an example scenario in which tracers 728a and 728b stored in a flow barrier 708 can provide information on properties of the reservoir 705. Generally, numerical simulations may be performed in a variety of different manners to provide a variety of different types information on fluid flow, geological properties, and/or other information relating to a subterranean reservoir. The example simulation shown in FIGS. 7A-7D was performed using a numerical finite difference representation of fluid flow through porous media, based on a multi-phase Darcy law. The simulator used in the examples shown was the QUIKLOOK® simulator of Halliburton Energy Services. The simulator transforms input data describing initial subterranean reservoir properties to generate output data describing subsequent subterranean reservoir properties. The same and/or different types computer software and/or hardware may be used to numerically simulate these and/or other features of a subterranean reservoir.

FIG. 7A shows a diagram 700a of permeability in the reservoir 705. The shading of each rectangle in the diagram 700a indicates an approximate magnitude of reservoir permeability in an “x” direction in the region represented by the rectangle. The “x” direction is indicated by the coordinate axes 752 in the diagram 700a. The range of permeability magnitudes represented by each type of shading is shown in units of milliDarcy (mD) in the shading legend 754a. For example, permeability values in the range of 0 mD to 1 mD are represented in the diagram 700a by the shading type at the top of the legend 754a, permeability values in the range of 1 mD to 100 mD are represented in the diagram 700a by the shading type second from the top of the legend 754a, etc. In the example numerical simulations, the reservoir 705 had an average permeability of 40 mD, an average porosity of 0.24, and has an initial oil saturation of 0.63; the reservoir 705 was approximately 1320 feet by 1320 feet in areal extent (in the xy-plane) and approximately 450 feet thick (in the direction perpendicular to the xy-plane). The values of porosity shown and described with respect to the numerical simulations of FIGS. 7A-7D refer to the fraction of the pore space available for fluid to saturate. As such, the values of porosity are unitless values between zero and one. The values of saturation shown and described with respect to the numerical simulations of FIGS. 7A-7D refer to the fraction of the pore space containing water (for water saturation) or oil (for oil saturation). As such, the values of water saturation and oil saturation are unitless values between zero and one.

The example reservoir 705 shown in FIGS. 7A-7D includes an injection well 704, a production well 703, and a barrier 708 between the wells 704, 703. In the example simulation, the injection well 704 injects water into the reservoir 705, and the production well 703 receives fluids from the reservoir 705 and communicates the received fluids to a surface. The reservoir 705 includes a high permeability channel 750. The high permeability channel 750 transmits fluids in the x direction more readily than the surrounding portions of reservoir 705 shown in the diagram 700a. In the example numerical simulation, the barrier 708 has a permeability less than 1 mD in the x direction, the high permeability channel 750 has a permeability of approximately 600 mD, and the remaining portions of the reservoir 705 have a permeability between 1 and 100 mD.

The barrier 708 includes two types of tracers 728a, 728b, each stored in a different portion of the barrier 708. The first type of tracer 728a is stored in a first portion of the barrier 708 (in a first range of “y” coordinates), and the second type of tracer 728b is stored in a second portion of the barrier 708 (in a second range of “y” coordinates). The high permeability channel 750 intersects the barrier 708 at the second portion of the barrier 708 where the second type of tracer 728b resides. In the example shown, the presence of the high permeability channel 750 intersecting the second portion of the barrier 708 may result in detection of the second type of tracer 728b at the production well 703 in greater quantities than the first type of tracer 728a. As such, analysis of tracer detection at the production well 703 may indicate properties of the high permeability channel 750, such as locations where the channel 750 intersects the barrier 708, directions of flow in the channel 750, and/or other properties. As a result of such detection and analysis, additional barriers may be formed, existing barriers may be modified, operation of the production well 703, the injection well 704, and/or another well may be modified, a new well can be designed, and/or other changes can be made to improve production.

FIG. 7B includes a diagram 700b showing oil saturation in the reservoir 705 after approximately 16 years of production at the production well 703. The shading of each rectangle in the diagram 700b indicates an approximate magnitude of oil saturation in the region represented by the rectangle. The range of oil saturation represented by each type of shading is shown in the shading legend 754b. FIG. 7C includes a diagram 700c showing water saturation in the reservoir 705 after approximately 20 years of production at the production well 703. The shading of each rectangle in the diagram 700c indicates an approximate magnitude of water saturation in the region represented by the rectangle. The range of water saturation represented by each type of shading is shown in the shading legend 754c. (In FIGS. 7B and 7C, the barrier 708 and the high permeability channel 750 are present in the reservoir 705 but are not shown in the diagrams 700b and 700c.)

FIG. 7D is a diagram 700d of water saturation from another example numerical simulation of an injection treatment. The numerical simulation represented in FIG. 7D was performed by a data processing apparatus based on a model of a subterranean reservoir 805. The numerical simulation represented in FIG. 7D is identical to the numerical simulation represented in FIG. 7C, except that the subterranean reservoir 805 shown in FIG. 7D does not include the barrier 708 or the tracers 728a, 728b that are included in the subterranean reservoir 705 shown in FIGS. 7A-7C. The diagram 700d shows water saturation in the reservoir 805 after approximately 20 years of production at the production well 703. The shading of each rectangle in the diagram 700d indicates an approximate magnitude of water saturation in the region represented by the rectangle. The range of water saturation represented by each type of shading is shown in the shading legend 754d.

The simulation represented in the diagram 700d of FIG. 7D allows comparison with the simulation represented in diagram 700c of FIG. 7C. In the reservoir 805 that does not include the barrier 708, water transits preferentially in the channel, resulting at nine years in cumulative oil production of 5.6 million barrels (bbl) and water production of 821 thousand bbl. By contrast, in the reservoir 705 that does include the barrier 708, water transmission in the reservoir is altered, and at nine years the cumulative oil production is 6.4 million bbl and the cumulative water production is 32 bbl. As such, in the example shown, numerical simulations indicate that at nine years of production the presence of the barrier 708 increases the volume of oil produced by the production well 703 and reduces the volume of water produced by the production well 703.

A number of embodiments of the invention have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the invention. Accordingly, other embodiments are within the scope of the following claims.

Claims

1. A method for monitoring fluid flow in a subterranean reservoir, the method comprising:

injecting a sealant mixture into a subterranean reservoir to form a flow barrier in the subterranean reservoir, the sealant mixture comprising a sealant material and a tracer; and

detecting the tracer displaced from the flow barrier by fluid flow in the subterranean reservoir.

2. The method of claim 1, wherein detecting the tracer comprises detecting the tracer in fluids received into a well bore in the subterranean reservoir.

3. The method of claim 2, wherein the fluids comprise a treatment fluid injected into the subterranean reservoir through a different well bore.

4. The method of claim 1, wherein injecting the sealant mixture comprises injecting a chemical tracer mixed with the sealant material.

5. The method of claim 1, wherein injecting the sealant mixture comprises injecting a radioactive tracer mixed with the sealant material.

6. The method of claim 1, wherein injecting the sealant mixture comprises injecting a noble gas tracer mixed with the sealant material.

7. The method of claim 1, wherein injecting the sealant mixture comprises injecting an active radio frequency tracer device mixed with the sealant material.

8. The method of claim 1, wherein injecting the sealant mixture comprises injecting a water-soluble tracer mixed with the sealant material.

9. The method of claim 1, wherein injecting the sealant mixture comprises injecting a hydrocarbon-soluble tracer mixed with the sealant material.

10. The method of claim 1, wherein injecting the sealant mixture comprises injecting the sealant mixed with a tracer that includes a coating adapted to dissolve when contacted by a particular fluid.

11. The method of claim 1, wherein the sealant in the subterranean reservoir reduces fluid flow through the flow barrier.

12. The method of claim 1, wherein the sealant in the subterranean reservoir prevents fluid flow through the flow barrier.

13. The method of claim 1, wherein the sealant mixture comprises a first sealant mixture comprising a first tracer, the method further comprising:

injecting a second sealant mixture into the subterranean reservoir to form a second flow barrier in the subterranean reservoir, the second sealant mixture comprising the sealant material and a second tracer; and

detecting the second tracer displaced from the second flow barrier by fluid flow in the subterranean reservoir.

14. The method of claim 1, wherein the sealant mixture comprises a first sealant mixture comprising a first tracer, and the first sealant mixture forms a first portion of the flow barrier, the method further comprising:

injecting a second sealant mixture into the subterranean reservoir to form a second portion of the flow barrier, the second sealant mixture comprising the sealant material and a second tracer; and

detecting the second tracer displaced from the flow barrier by fluid flow in the subterranean reservoir.

15. A system for monitoring fluid flow in a subterranean reservoir, the system comprising:

a treatment well that injects treatment fluid into a subterranean reservoir to displace hydrocarbon fluid in the subterranean reservoir, the subterranean reservoir comprising a flow barrier that stores a tracer; and

a detector adapted to detect the tracer displaced from the flow barrier in at least one of the hydrocarbon fluid or the treatment fluid.

16. The system of claim 15, wherein the detector comprises a down hole detector installed in the well bore and adapted to detect the tracer released from the flow barrier.

17. The system of claim 15, wherein the detector comprises a detector located exterior the well bore and adapted to detect the tracer released from the flow barrier.

18. The system of claim 15, further comprising a computing subsystem that analyzes fluid flow in the subterranean reservoir based on data provided by the detector.

19. The system of claim 15, wherein the treatment fluid comprises water and the hydrocarbon fluid comprises oil.

20. The system of claim 15, wherein the tracer comprises a salt stored in the barrier and detecting the tracer comprises detecting a change of resistivity of at least one of the hydrocarbon fluid or the treatment fluid.

21. A method for analyzing fluid flow in a subterranean reservoir, the method comprising:

forming a flow barrier in a subterranean reservoir, the flow barrier comprising a tracer; and

analyzing fluid flow in the subterranean reservoir based on detecting the tracer in fluids received into a well bore from the subterranean reservoir.

22. The method of claim 21, wherein analyzing fluid flow in the subterranean reservoir comprises identifying that the fluids contacted the flow barrier in the subterranean reservoir.

23. The method of claim 21, wherein analyzing fluid flow in the subterranean reservoir comprises identifying locations in the subterranean reservoir where the fluids contacted the flow barrier.

24. The method of claim 21, wherein analyzing fluid flow in the subterranean reservoir comprises identifying a breach in the flow barrier.

25. The method of claim 21, wherein forming the non-conductive barrier comprises injecting the tracer and a sealant material into the subterranean reservoir.