(19) United States (12) Patent Application Publication (10) Pub. N0.2 US 2011…sep · 2015. 5. 27. · US 20110277996A1 (19) United States (12) Patent Application Publication (10)

US 20110277996A1

(19) United States (12) Patent Application Publication (10) Pub. N0.2 US 2011/0277996 A1

Cullick et al. (43) Pub. Date: NOV. 17, 2011

(54) SUBTERRANEAN FLOW BARRIERS Publication Classi?cation CONTAINING TRACERS (51) Int- Cl

E21B 47/00 (2006.01) (75) Inventors: Alvin S. Cullick, Houston, TX E21B 43/16 (2006.01)

(US); Leld0n(M- )Farabee, (52) us. Cl. .................................... .. 166/250.12; 166/66 Houston, TX US ; Norm R. Warpinski, Cypress, TX (U S); (57) ABSTRACT Robert F- Shelley, Katy, TX (Us); Some aspects of the present disclosure include monitoring Stewart A- LeViIl, Cemennlal, CO ?uid ?oW in a subterranean reservoir. In some implementa (US) tions, a sealant mixture is injected into a subterranean reser

voir to form a ?oW barrier in the subterranean reservoir. The (73) Assigneez Halliburton Energy services Inc_ sealant mixture includes a sealant material and a tracer. The

Houston TX (Us) ’ ’ tracer may be stored in the ?oW barrier, and the tracer may be ’ displaced from the ?oW barrier, for example, by ?uid ?oW in

the subterranean reservoir. The displaced tracer may be (21) APP1- NOJ 12/777,965 detected, for example, in ?uid produced into a Well bore in the

subterranean reservoir. Fluid ?oW in the subterranean reser (22) Filed; May 11, 2010 voir may be analyzed based on detection of the tracer.

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US 2011/0277996 A1

SUBTERRANEAN FLOW BARRIERS CONTAINING TRACERS

BACKGROUND

[0001] Production of resources from a subterranean reser voir can be enhanced by injecting ?uids into the reservoir to displace or sWeep the resources to a production Well. For example, Water, steam, and/or other ?uids 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 in?uence hoW the injected ?uids and hydro carbons ?oW through the reservoir. Fractures are typically formed in a reservoir to increase the ?uid conductivity of the reservoir. Non-conductive barriers may also be formed in the reservoir to prevent the ?oW of ?uid in a certain region of the reservoir. Such non-conductive barriers can be formed by injecting loW permeability materials into fractures in the res ervoir, including hydraulically induced fractures and/ or natu ral fractures. The resulting non-conductive barriers divert the ?oW of injected Water or steam, and thereby increase the volume of the reservoir sWept by the injected ?uids.

SUMMARY

[0002] In a general aspect, a tracer is stored in a subterra nean ?oW barrier. The tracer may be released or displaced from the ?oW barrier and detected. In some cases, ?uid ?oW may be analyzed based on the tracer. [0003] In one aspect, a method for monitoring ?uid ?oW in a subterranean reservoir includes injecting a sealant mixture into a subterranean reservoir to form a ?oW barrier in the subterranean reservoir. The sealant mixture includes a sealant material and a tracer. The tracer may remain in the ?oW barrier for a period of time. The tracer is displaced from the ?oW barrier by ?uid ?oW in the subterranean reservoir, and the displaced tracer is detected. [0004] Implementations may include one or more of the folloWing features. Detecting the tracer includes detecting the tracer in ?uids received into a Well bore in the subterranean reservoir. The ?uid ?oW includes ?oW of a treatment ?uid 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 ?uid. The sealant in the sub terranean reservoir prevents ?uid ?oW through the ?oW bar rier. The sealant mixture is a ?rst sealant mixture that includes a ?rst tracer. A second sealant mixture includes a second tracer. The second sealant mixture is injected into the subter ranean reservoir to form a second ?oW barrier in the subter ranean reservoir. The second tracer is displaced from the second ?oW barrier by ?uid ?oW in the subterranean reservoir. The second tracer displaced from the second ?oW barrier is detected. The ?rst sealant mixture forms a ?rst portion of the ?oW barrier. A second sealant mixture is injected into the subterranean reservoir to form a second portion of the ?oW

Nov. 17, 2011

barrier. The second tracer is displaced from the ?oW barrier by ?uid ?oW in the subterranean reservoir. The second tracer displaced from the ?oW barrier is detected. [0005] In one aspect, a system for monitoring ?uid ?oW in a subterranean reservoir includes a treatment Well and a detector. The treatment Well injects treatment ?uid into a subterranean reservoir to displace hydrocarbon ?uid in the subterranean reservoir. The subterranean reservoir includes a ?oW barrier that stores a tracer. The detector is adapted to detect the tracer displaced from the ?oW barrier by the hydro carbon ?uid and/ or the treatment ?uid. [0006] Implementations may include one or more of the folloWing features. The detector includes a doWn hole detec tor installed in the Well bore and adapted to detect the tracer released from the ?oW barrier. The detector includes a detec tor located exterior the Well bore and adapted to detect the tracer released from the ?oW barrier. The system includes a computing subsystem that analyZes ?uid ?oW in the subter ranean reservoir based on data provided by the detector. The treatment ?uid is Water and the hydrocarbon ?uid is oil. The tracer includes a salt stored in the barrier. Detecting the tracer includes detecting a change of resistivity of the hydrocarbon ?uid and/or the treatment ?uid. [0007] In one aspect, a method for analyZing ?uid ?oW in a subterranean reservoir includes forming a ?oW barrier in a subterranean reservoir. The ?oW barrier includes a tracer. Fluid ?oW in the subterranean reservoir is analyZed based on detecting the tracer in ?uids received into a Well bore from the subterranean reservoir. [0008] Implementations may include one or more of the folloWing features. AnalyZing ?uid ?oW in the subterranean reservoir includes identifying that the ?uids contacted the ?oW barrier in the subterranean reservoir. AnalyZing ?uid ?oW in the subterranean reservoir includes identifying a breach in the ?oW barrier. Forming the non-conductive barrier includes injecting the tracer and a sealant material into the subterranean reservoir. AnalyZing the ?uid ?oW includes identifying a direction of ?uid ?oW in the subterranean res ervoir. Geological features of the subterranean reservoir, for example geological heterogeneity, causes ?uid to ?oW in multiple different directions, and analyZing the ?uid ?oW includes identifying the directions of ?uid ?oW and/or the geological features.An injection treatment is designed and/or modi?ed based on detecting the tracers and/or on the analysis of the ?uid ?oW. Designing the injection treatment includes selecting a location to inject treatment ?uid, selecting a vol ume of treatment ?uid to inject, selecting properties of a ?oW barrier to be formed. The injection treatment may be designed and/or modi?ed to improve recovery of hydrocarbons from the reservoir.

DESCRIPTION OF DRAWINGS

[0009] FIG. 1 is a diagram of an example Well system that includes a barrier in a subterranean reservoir.

[0010] FIG. 2 is a diagram of an example Well system storing reservoir tracers in subterranean barriers. [0011] FIG. 3 is a diagram of an example treatment Well. [0012] FIG. 4 is a diagram of an example Well system detecting tracers released into a subterranean reservoir from a barrier. [0013] FIG. 5 is a diagram of an example Well system detecting tracers released into a subterranean reservoir from a barrier.

US 2011/0277996 A1

[0014] FIG. 6 is a ?ow chart showing an example technique for analyzing ?uid ?ow in a reservoir. [0015] FIGS. 7A-7D are diagrams of subterranean reser voir properties from example simulations. [0016] Like reference symbols in the various drawings indicate like elements.

DETAILED DESCRIPTION

[0017] 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 perme able 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. [0018] A production well 103 may extend through a hydro carbon-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 ?uids. Typically, the water-bearing area may include a small proportion of hydrocarbon and/or other mate rials, the hydrocarbon-bearing area may include a small pro portion of water and/or other materials, and the areas may overlaps in an intermediate area containing varying propor tions 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. [0019] The reservoir 105 includes multiple subterranean fractures 106 in ?uid 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 pro duction well 103. The fractures 106 include transverse frac tures, 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. [0020] The fractures 106 may contain proppant material injected into the fractures 106 to hold the fractures 106 open for resource production. Fluids typically ?ow 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

Nov. 17, 2011

the reservoir 1 05 may be several orders of magnitude less than the permeability in the fractures 106. [0021] The subterranean region 101 includes multiple bar riers 108 adjacent the production well 103. Each barrier 108 includes sealant material that inhibits ?uid ?ow 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 signi?cantly 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 ?uids to improve sweep. [0022] As shown in FIG. 1, the well bore 103 includes a ?uid control unit 107 that can prevent axial ?ow through the well bore that would circumvent the ?ow barrier 108. For example, a bridge plug or other Zonal isolation device may be installed in the well bore to prevent axial ?ow through the well bore that would circumvent the ?ow barrier 108. [0023] Fluid ?ow within a reservoir may be modi?ed by the presence of a barrier. Selective or non-selective ?ow barriers may modify ?ow patterns within an entire reservoir or por tions of a reservoir. In some implementations, a sealant that includes a relative permeability modi?er may allow hydro carbon materials to selectively ?ow through the barrier in relation to an aqueous ?uid. In some implementations, mul tiple barriers may have varying permeabilities, and a series of barriers may guide the ?ow of at least one desired ?uid, for example, to a producing well. In some cases, multiple selec tive and/or non-selective barriers may be used to modify the ?ow regime inside the hydrocarbon reservoir to improve the volumetric sweep e?iciency of the hydrocarbons in the for mation. The sealant and ?uid used to provide the driving force for ?ow and sweep the hydrocarbon ?uids can be selected to improve and/ or maximiZe the amount of hydrocarbons recov ered in a hydrocarbon reservoir.

[0024] A barrier 108 can be formed by injecting sealant material into the reservoir, for example, through the produc tion well 103 and/ or another well. Injecting the sealant mate rial may fracture the reservoir rock as the sealant is injected, and/or the sealant material may be injected into existing frac tures. 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 natu ral fractures. The barriers 108 may extend at any angle, ori entation, 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 ?uid state through the tubing and through the perforations and into the fracture to be sealed until a suf?cient volume of sealant has been placed into the fracture to provide the ?ow barrier. [0025] Treatment ?uids 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 ?uids may be injected into the reservoir

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105 through the treatment Well 104. The injected treatment ?uid 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 ?uid 110 may be injected in connection With a ?re?ood treatment, steam assisted gravity drainage treatment, and/ or many other types of treatments that mobilize hydrocarbons in the reservoir 1 05. Barriers 108 in the reservoir 105 may in?uence the ?oW of treatment ?uids 110 and hydrocarbon resources in the reser voir 105. The barriers 108 can be designed to improve sWeep e?iciency in the reservoir 105. The arroWs 116 shoW an example pattern of ?uid ?oW through the reservoir 105, Where the ?oW is diverted by the barriers 108. As illustrated by the arroWs 116 in FIG. 1, the treatment ?uid 110 ?oWs through the reservoir 1 05 toWard the production Well 1 03, contacts the barriers 108, and ?oWs into the production Well 103 through the fractures 106. In the example shoWn, the barriers 108 divert the treatment ?uid 110 aWay from the production Well 103 and cause the treatment ?uid to sWeep a larger region of the reservoir 105. Increasing the volume of the reservoir 105 that is sWept by the treatment ?uid 110 may enhance resource production from the reservoir 105. Barriers may be designed to in?uence ?uid ?oW in the reservoir 105 in a different manner than the examples shoWn.

[0026] As shoWn in FIGS. 2, 4, and 5, barriers may contain reservoir tracers that can be used to analyZe the ?oW of ?uid in the reservoir 105. The tracers can be stored in the barriers 108, 208, 408, 508a, 5081). 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 res ervoir. When a tracer is displaced from the barrier, it may be released and/or transported out of and/or aWay from the bar rier. Contact by a particular type of ?uid 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 ?uid ?oW in the reservoir. In some instances, the treatment ?uid 110 is injected With treatment ?uid tracers through the treatment Well 104. Such treatment ?uid tracers injected With the treat ment ?uid 110 are traditionally used to identify the treatment Well 104 as the source of the treatment ?uid 110. The tracers stored in the barriers are injected With the sealant that forms the barriers, rather than being injected With the treatment ?uid 110. As such, the tracers stored in the barriers may be used in some cases to identify and/or analyZe additional and/or dif ferent types of information than the traditional treatment ?uid tracers injected With the treatment ?uid 110.

[0027] 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 ?uid ?oW in the reservoir 105. For example, detecting the tracer may indicate that the ?uid containing the tracer interacted With one or more of the barriers 108. Detecting the tracers may provide additional and/ or different information. For example, detect ing tracers may provide spatio-temporal inforrnation regard ing ?uid ?oW patterns in the reservoir 105. Fluid ?oW patterns may indicate the location of a barrier breach, connectivity of subterranean fractures, rates of ?uid ?oW in the reservoir 1 05, regions of loW ?uid conductivity in the reservoir 105, regions of high ?uid conductivity in the reservoir 105, and/or other information. Detecting tracers may indicate a type of ?uid (e. g., oil, Water, etc.) contacting the barrier 108, and/ or other

Nov. 17, 2011

information regarding ?uid ?oW in the reservoir 105. Detect ing 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.

[0028] In some implementations, a computing system ana lyZes data received from a tracer detection subsystem and analyZes the data to provide information describing ?uid ?oW 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 measure ments 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 ?uid ?oW patterns in the reservoir 105, Which may identify paths of ?uid ?oW in the reservoir 105, barrier breaches, fracture locations, ?uid ?oW rates, and/ or other information. [0029] The Well system 100 may be modi?ed 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 sub systems may be installed, adjusted, activated, terminated, or otherWise modi?ed based on the information provided by the tracers. In some cases, ?uid injection at the treatment Well 104 can be modi?ed, locations and character istics of the barriers 108 can be modi?ed, additional barriers can be formed in the reservoir 1 05, additional fractures can be formed in the reservoir 105, production tubing and packers in the production Well 103 can be recon?gured, and/or other modi?cations 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 operationsiand may be based exclusively, partially, primarily, secondarily, directly, or indi rectly on the one or more other items or operations. In some implementations, the modi?cations of the Well system 100 are selected and/or parameteriZed to improve production from the reservoir 105. For example, the modi?cations may improve the sWeep e?iciency of the treatment ?uids 110. In some implementations, the modi?cations of the Well system 100 are selected and/or parameteriZed by the computing sys tem based on data analysis performed by the computing sys tem

[0030] 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 ?oW in the barrier 208. The sealant 226 may include materials that harden and/or become less viscous in the barrier 208. [0031] In some implementations, the sealant used to pro vide the barrier may be any material capable of selectively or non-selectively reducing the ?oW of one or more ?uids Within a subterranean formation. A non-selective barrier substan tially seals the fracture. A selective barrier modi?es the per meability or relative permeability to alloW ?uids to selec tively ?oW 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 ?uids, epoxy-based ?uids, magnesium based slurries, metallic particles, a clay based slurry (e.g., a bentonite based slurry), an emulsion, a precipitate (e.g., a

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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.

[0032] A subterranean barrier may incorporate compo nents With physical properties that aid remote geophysical measurement of the barrier geometry and/ or the internal bar rier 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., detect able) 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 surround ing reservoir 205. [0033] The sealant 226 can be injected in a ?uid 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 ?uid migration. An example sealant is H2ZEROTM, an organically cross-linked polymer that can be used to fracture the reservoir and form a ?oW barrier in the resulting fracture. Other seal ants 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 emul sions, 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. [0034] In some implementations, the sealant may include sWellable particles. A sWellable particle can sWell upon con tact With a ?uid, for example, an aqueous ?uid, an oil-based ?uid, gas, and/or others. In some instances, sWellable par ticles 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 approxi mately 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 ?uid or an aqueous-based ?uid. SWelling elastomers may be used to activate tracers, for example, by crushing a capsule When the elastomer expands upon contact With hydrocarbons or other ?uids. Some speci?c examples of sWellable elastomers that sWell in the presence of an oil-based ?uids include natural rubbers, acrylate butadiene rubbers, isoprene rubbers, chloroprene rubbers, butyl rub bers, brominated butyl rubbers, chlorinated butyl rubbers, chlorinated polyethylenes, neoprene rubbers, styrene butadi ene copolymer rubbers, chlorinated polyethylene, sulpho nated polyethylenes, ethylene acrylate rubbers, epichlorohy drin ethylene oxide copolymers, epichlorohydrin terpolymer, ethylene-propylene rubbers, ethylene vinyl acetate copoly mers, ethylene-propylene-diene terpolymer rubbers, ethyl ene vinyl acetate copolymer, nitrile rubbers, acrylonitrile butadiene rubbers, hydrogenated acrylonitrile butadiene rub bers, carboxylated high-acrylonitrile butadiene copolymers, polyvinylchloride-nitrile butadiene blends, ?uorosilicone rubbers, silicone rubbers, poly 2,2,l-bicyclo heptenes

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(polynorbornene), alkylstyrenes, polyacrylate rubbers such as ethylene-acrylate copolymer, ethylene-acrylate terpoly mers, ?uorocarbon polymers, copolymers of poly(vinylidene ?uoride) and hexa?uoropropylene, terpolymers of poly(vi nylidene ?uoride), hexa?uoropropylene, and tetra?uoroeth ylene, terpolymers of poly(vinylidene ?uoride), polyvinyl methyl ether and tetra?uoroethylene, per?uoroelastomers such as tetra?uoroethylene per?uoroelastomers, highly ?u orinated elastomers, butadiene rubber, polychloroprene rub ber, polyisoprene rubber, polynorbomenes, polysul?de rub bers, polyurethanes, silicone rubbers, vinyl silicone rubbers, ?uoromethyl silicone rubber, ?uorovinyl silicone rubbers, phenylmethyl silicone rubbers, styrene-butadiene rubbers, copolymers of isobutylene and isoprene knoWn as butyl rub bers, brominated copolymers of isobutylene and isoprene, chlorinated copolymers of isobutylene and isoprene, and any combination thereof. An example of a commercially avail able product including such sWellable particles may include a commercially available product from Easy Well Solutions, in NorWay, under the trade name “EASYWELL.”

[0035] Examples of ?uoroelastomers that sWell in the pres ence of an oil-based ?uid include copolymers of vinylidene ?uoride and hexa?uoropropylene and terpolymers of vinylidene ?uoride, hexa?uoropropylene and tetra?uoroeth ylene. Fluoroelastomers include elastomers that may have one or more vinylidene ?uoride units (“VF2” or “VdF”), one or more hexa?uoropropylene units (“HEP”), one or more tetra?uoroethylene units (“TEE”), one or more chlorotri?uo roethylene (“CTFE”) units, and/or one or more per?uoro (alkyl vinyl ether) units (“PAVE”), such as per?uoro(methyl vinyl ether) (“PMVE”), per?uoro(ethyl vinyl ether) (“PEVE”), and per?uoropropyl vinyl ether (“PPVE”). These elastomers can be homopolymers or copolymers. Some ?uo roelastomers contain vinylidene ?uoride units, hexa?uoro propylene units, and, optionally, tetra?uoroethylene units and ?uoroelastomers containing vinylidene ?uoride units, per ?uoroalkyl per?uorovinyl ether units, and tetra?uoroethylene units, such as the vinylidene ?uoride type ?uoroelastomer knoWn under the trade designation “AFLAS®” available from Asahi Glass Co., Ltd. Copolymers may include vinylidene ?uoride and hexa?uoropropylene units may. If the ?uoropolymers contain vinylidene ?uoride units, the poly mers may contain up to 40 mole %VF2 units, e.g., 30-40 mole %. If the ?uoropolymers contain hexa?uoropropylene units, the polymers may contain up to 70 mole % HFP units. If the ?uoropolymers contain tetra?uoroethylene units, the poly mers may contain up to 10 mole % TFE units. When the ?uoropolymers contain chlorotri?uoroethylene the polymers may contain up to 10 mole % CTFE units. When the ?uo ropolymers contain per?uoro(methyl vinyl ether) units, the polymers may contain up to 5 mole % PMVE units. When the ?uoropolymers contain per?uoro(ethyl vinyl ether) units, the polymers may contain up to 5 mole % PEVE units. When the ?uoropolymers contain per?uoro(propyl vinyl ether) units, the polymers may contain up to 5 mole % PPVE units. The ?uoropolymers may contain 66%-70% ?uorine. An example commercially available ?uoroelastomer is knoWn under the trade designation “TECHNOFLON FOR HS®” sold by Ausimont USA. This material contains “Bisphenol AF” manufactured by Halocarbon Products Corp. Another com mercially available ?uoroelastomer 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% ?uorine. Another suitable commercially

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available ?uoroelastomer 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 designa tion “FL80-4” available from Oil States Industries, Inc., Arlington, Tex.; and the product knoWn under the trade des ignation “DMS005” available from Duromould, Ltd., Lon donderry, Northern Ireland. [0036] 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. Unsatur ated 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 ?uid 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 avail able grades of organic peroxides, as Well as other vulcaniZa tion agents, may be used. The resulting elastomeric compo sitions may include non-porous or porous, sWelled, acid grafted rubbers, Which may or may not be vulcaniZed. VulcaniZation may refer to a physicochemical change result ing 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 mono mers, either grafted onto the polymer backbone or blended therein, may act together to cost-effectively increase the Water- and/or oil-sWellability of oil?eld 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 ?uid sWellability, depending on the type of inorganic additives and monomers used.

[0037] Elastomers such as nitrile rubber, hydrogenated nitrile rubber (HNBR), ?uoroelastomers, or acrylate-based elastomers, or their precursors, if added in variable amounts to an EPDM polymer or its precursor monomer mixture, along With a suf?cient amount (from approximately 1 to 10 phr) of an unsaturated organic acid, anhydride, or salt thereof, such as maleic acid, optionally combined With a suf?cient amount (from approximately 1 to 10 phr) an inorganic sWell

Nov. 17, 2011

ing 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 su?icient 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 ?uids such as completion ?uids containing Zinc bromide. A second addition of a suf?cient 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 suf?cient amount (from 1 to 20 phr) of ZWitterionic polymer or copolymer of a ZWitterionic mono mer 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 ?uids, 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.

[0038] 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 oil?eld industry in loss circulation ?uids and is resistant to doWn hole chemicals and environments.

[0039] Other sWellable elastomers behave in a similar fash ion With respect to aqueous ?uids. Some speci?c examples of suitable sWellable elastomers that sWell in the presence of an aqueous-based ?uid, include starch-polyacrylate acid graft copolymer, polyvinyl alcohol cyclic acid anhydride graft copolymer, polyacrylamide, poly(acrylic acid-co-acryla mide), poly(2-hydroxyethyl methacrylate), poly(2-hydrox ypropyl methacrylate), isobutylene maleic anhydride, acrylic acid type polymers, vinylacetate-acrylate copolymer, poly ethylene oxide polymers, carboxymethyl cellulose type poly mers, starch-polyacrylonitrile graft copolymers and the like, and highly sWelling clay minerals such as sodium bentonite having montmorillonite as main ingredient, and combina tions thereof.

[0040] Additional Water sWellable particles may include particulate matter embedded in a matrix material. One example of such particulate matter is salt, including dissoci ating salt, Which can be uniformly compounded into a base rubber. Suitable salts may include acetates, bicarbonates, car bonates, formates, halides (MxHy) (HICl, Br or I), hydrosul phides, hydroxides, imides, nitrates, nitrides, nitrites, phos phates, 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.

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[0041] 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 oxy gen 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, alde hydes, 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. [0042] Combinations of suitable sWellable elastomers may also be used. In some implementations, some of the elas tomers that sWell in oil-based ?uids may also sWell in aque ous-based ?uids. Elastomers that may sWell in both aqueous based and oil-based ?uids, include ethylene propylene rubbers, ethylene-propylene-diene terpolymer rubbers, butyl rubbers, brominated butyl rubbers, chlorinated butyl rubbers, chlorinated polyethylene, neoprene rubbers, styrene butadi ene copolymer rubbers, sulphonated polyethylenes, ethylene acrylate rubbers, epichlorohydrin ethylene oxide copolymer, silicone rubbers and ?uorosilicone rubbers, and any combi nation thereof. Appropriate ?uids may be used to sWell the sWellable elastomer compositions. [0043] In some implementations, the sWellable elastomers may be crosslinked and/or lightly crosslinked. Other sWellable elastomers behave in a similar fashion With respect to ?uids. 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. [0044] SWellable particles may be included in an amount suf?cient to provide the desired barrier properties. In some implementations, the sWellable particles may be placed in a fracture or void in a treatment ?uid including an amount up to approximately 50% by volume of the treatment ?uid. In some implementations, the sWellable particles may be present in a range of approximately 5% to approximately 95% by volume of the treatment ?uid used to place the particles. [0045] 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-de?ned physical shape as Well as an irregular geometry, including the physical shape of platelets, shavings, ?bers, ?akes, 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. [0046] The sealant may include a cement. An example of a cement includes hydraulic cement, Which may include cal cium, aluminum, silicon, oxygen, and/or sulfur and Which sets and hardens by reaction With Water. Examples of hydrau

Nov. 17, 2011

lic 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 micro?ne cement, for example, MICRO DUR RU micro?ne cement available from Dyckerhoff GmBH of Lengerich, Germany. Combinations of cements and sWellable particles may also be used. [0047] The sealant may include a Water soluble relative permeability modi?er. A relative permeability modi?er may refer to a compound capable of reducing the permeability of a subterranean formation to aqueous-based ?uids Without substantially changing its permeability to hydrocarbons. In some implementations, the Water-soluble relative permeabil ity modi?ers may include a hydrophobically modi?ed poly mer. “Hydrophobically modi?ed” 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 modi?ers include a hydrophilically modi?ed polymer. “Hydrophilically modi ?ed” refers to the incorporation into the hydrophilic polymer structure of hydrophilic groups. In some implementations, the Water-soluble relative permeability modi?ers include a Water-soluble polymer Without hydrophobic or hydrophilic modi?cation.

[0048] Hydrophobically modi?ed 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 modi?ed 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 modi?ed polymers include a polymer backbone that include polar heteroatoms. The polar heteroa toms present Within the polymer backbone of the hydropho bically modi?ed polymers may include oxygen, nitrogen, sulfur, and/ or phosphorous. [0049] In some implementations, the hydrophobically modi?ed polymers can be a reaction product of a hydrophilic polymer and a hydrophobic compound. The hydrophilic polymers for forming the hydrophobically modi?ed poly mers may be capable of reacting With hydrophobic com pounds. Suitable hydrophilic polymers include, homo-, co-, or terpolymers, for example, polyacrylamides, polyviny lamines, poly(vinylamines/vinyl alcohols), and alkyl acrylate polymers in general. Additional examples of alkyl acrylate polymers include polydimethylaminoethyl methacrylate, polydimethylaminopropyl methacrylamide, poly(acryla mide/dimethylaminoethyl methacrylate), poly(methacrylic acid/dimethylaminoethyl methacrylate), poly(2-acrylamido 2-methyl propane sulfonic acid/dimethylaminoethyl meth acrylate), poly(acrylamide/dimethylaminopropyl methacry lamide), poly(acrylic acid/dimethylaminopropyl methacrylamide), and poly(methacrylic acid/dimethylami nopropyl methacrylamide). In some implementations, the hydrophilic polymers include a polymer backbone and reac tive 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

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dimethyl amino pendant group and at least one monomer including dimethylaminoethyl methacrylate or dimethylami nopropyl methacrylamide. In some implementations, the hydrophilic polymers include a polymer backbone, the poly mer 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, chito sans, 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. [0050] 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; dode cenyl 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 com pound and hydrophilic polymer may result in the quatemiZa tion 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. [0051] In some implementations, hydrophobically modi ?ed polymers may be prepared from the polymerization reac tion of at least one hydrophilic monomer and at least one hydrophobically modi?ed hydrophilic monomer. [0052] A variety of hydrophilic monomers may be used to form hydrophobically modi?ed polymers. Examples of suit able hydrophilic monomers include homo-, co-, and terpoly mers of acrylamide, 2-acrylamido-2-methyl propane sulfonic acid, N,N-dimethylacrylamide, vinyl pyrrolidone, dimethy laminoethyl methacrylate, acrylic acid, dimethylaminopro pylmethacrylamide, vinyl amine, vinyl acetate, trimethylam moniumethyl methacrylate chloride, methacrylamide, hydroxyethyl acrylate, vinyl sulfonic acid, vinyl phosphonic acid, methacrylic acid, vinyl caprolactam, N-vinylforma mide, N,N-diallylacetamide, dimethyldiallyl ammonium halide, itaconic acid, styrene sulfonic acid, methacrylamido ethyltrimethyl ammonium halide, quaternary salt derivatives of acrylamide, and quaternary salt derivatives of acrylic acid. [0053] A variety of hydrophobically modi?ed hydrophilic monomers also may be used to form hydrophobically modi ?ed polymers. Examples of suitable hydrophobically modi ?ed 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 modi?ed hydrophilic monomer includes octadecyldimethylammoniumethyl methacrylate bromide, hexadecyldimethylammoniumethyl methacrylate bromide, hexadecyldimethylammoniumpropyl methacrylamide bro mide, 2-ethylhexyl methacrylate, or hexadecyl methacryla mide.

Nov. 17, 2011

[0054] The hydrophobically modi?ed polymers formed from the above-described polymeriZation reaction may have estimated molecular Weights in the range of from approxi mately 100,000 to approximately 10,000,000 and mole ratios of the hydrophilic monomer(s) to the hydrophobically modi ?ed hydrophilic monomer(s) in the range of from approxi mately 99.98:0.02 to approximately 90:10. Hydrophobically modi?ed polymers having molecular Weights and mole ratios in the ranges set forth above include acrylamide/octade cyldimethylammoniumethyl methacrylate bromide copoly mer, dimethylaminoethyl methacrylate/hexadecyldimethy lammoniumethyl methacrylate bromide copolymer, dimethylaminoethyl methacrylate/vinyl pyrrolidone/hexade cyldimethylammoniumethyl methacrylate bromide terpoly mer and acrylamide/2-acrylamido-2-methyl propane sul fonic acid/2-ethylhexyl methacrylate terpolymer. [0055] In some implementations, the Water-soluble relative permeability modi?ers include a hydrophilically modi?ed polymer. Hydrophilically modi?ed polymers typically have molecular Weights in the range of from approximately 100, 000 to approximately 10,000,000. In some implementations, the hydrophilically modi?ed polymers include a polymer backbone, the polymer backbone including polar heteroat oms. The polar heteroatoms present Within the polymer back bone of the hydrophilically modi?ed polymers may include oxygen, nitrogen, sulfur, and/or phosphorous. [0056] In some implementations, a hydrophilically modi ?ed polymer may be a reaction product of a hydrophilic polymer and a hydrophilic compound. Hydrophilic polymers suitable for forming hydrophilically modi?ed polymers may be capable of reacting With hydrophilic compounds. In some implementations, hydrophilic polymers include homo-, co-, or terpolymers, for example, polyacrylamides, polyviny lamines, poly(vinylamines/vinyl alcohols), and alkyl acrylate polymers in general. Additional examples of alkyl acrylate polymers include polydimethylaminoethyl methacrylate, polydimethylaminopropyl methacrylamide, poly(acryla mide/dimethylamino ethyl methacrylate), poly(methacrylic acid/dimethylaminoethyl methacrylate), poly(2-acrylamido 2-methyl propane sulfonic acid/dimethylaminoethyl meth acrylate), poly(acrylamide/dimethylaminopropyl methacry lamide), poly (acrylic acid/dimethylaminopropyl methacrylamide), and poly(methacrylic acid/dimethylami nopropyl methacrylamide). In some implementations, the hydrophilic polymers include a polymer backbone and reac tive 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 dimethylami nopropyl 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. Suit able hydrophilic polymers that include polar heteroatoms Within the polymer backbone include homo-, co-, or terpoly mers, such as celluloses, chitosans, polyamides, poly etheramines, 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

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starch, such as corn, maize, Waxy maize, potato, tapioca, and the like, With the reaction product of epichlorohydrin and trialkylamine. [0057] 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 copoly mers, terpolymers, and mixtures thereof. In some implemen tations, the polyether includes an epichlorohydrin-terminated polyethylene oxide methyl ether. [0058] Hydrophilically modi?ed 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 approxi mately 1:1 to approximately 10:1. Hydrophilically modi?ed polymers having molecular Weights and Weight ratios in the ranges set forth above include the reaction product of poly dimethylaminoethyl methacrylate and epichlorohydrin-ter minated polyethyleneoxide methyl ether; the reaction prod uct of polydimethylaminopropyl methacrylamide and epichlorohydrin-terminated polyethyleneoxide methyl ether; and the reaction product of poly(acrylamide/dimethylamino propyl methacrylamide) and epichlorohydrin-terminated polyethyleneoxide methyl ether. In some implementations, the hydrophilically modi?ed polymer includes the reaction product of a polydimethylaminoethyl methacrylate and epichlorohydrin-terminated polyethyleneoxide methyl ether having a Weight ratio of polydimethylaminoethyl methacry late to epichlorohydrin-terminated polyethyleneoxide methyl ether of approximately 3:1. [0059] In some implementations, the Water-soluble relative permeability modi?ers include a Water-soluble polymer With out hydrophobic or hydrophilic modi?cation. Examples of suitable Water-soluble polymers Without hydrophobic or hydrophilic modi?cation include homo-, co-, and terpoly mers of acrylamide, 2-acrylamido-2-methyl propane sulfonic acid, N,N-dimethylacrylamide, vinyl pyrrolidone, dimethy laminoethyl methacrylate, acrylic acid, dimethylaminopro pylmethacrylamide, vinyl amine, vinyl acetate, trimethylam moniumethyl methacrylate chloride, methacrylamide, hydroxyethyl acrylate, vinyl sulfonic acid, vinyl phosphonic acid, methacrylic acid, vinyl caprolactam, N-vinylforma mide, N,N-diallylacetamide, dimethyldiallyl ammonium halide, itaconic acid, styrene sulfonic acid, methacrylamido ethyltrimethyl ammonium halide, quaternary salt derivatives of acrylamide, and quaternary salt derivatives of acrylic acid. [0060] 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 res ervoir 205 (at least, not naturally present in quantities that exceed the detection threshold of tracer detection instru ments) that can be transported by means of ?uid 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 ?uids containing the tracer. Example chemical tracers include alcohols, salts, acids, and others. Radioactive tracers include substances that

Nov. 17, 2011

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 cho sen, for example, based on their half-life and/or other prop er‘ties. 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, microelectro mechanical (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 ?uorinated benZoic acid. Tracer devices may be used to detect and record properties of ?uid ?oW. For example, tracer devices may detect and record phase compo sition, ?oW velocity, location, and/or other data. Other example tracers include dyes, such as ?ourescein dyes, oil soluble dyes, and oil dispersible dyes; organic materials, such as guar, sugars, glycerol, surfactants, scale inhibitors, etc.; phosphorescent pigments; ?uorescent pigments; photolumi nescent pigments; oil dispersible pigments; metals; and/or others.

[0061] The tracers 228 can be selected for use in the system 200 based on their interaction or reaction to ?uids in the reservoir 205. Some tracers can be released from the barrier 208 When contacted by certain types of ?uid. For example, a tracer that dissolves in the treatment ?uid 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 ?uids to release the tracer. For example, the tracer may have a Water-soluble or hydrocarbon-soluble coating. A tracer may be stress acti vated. 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.

[0062] 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 50819 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 frac ture 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, ?oW 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.

[0063] The pump trucks 221 may include mobile vehicles, immobile installations, skids, hoses, tubes, ?uid tanks or res ervoirs, 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.

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[0064] The pump trucks 221 are coupled to the Working string 220 to communicate the sealant material 226, the trac ers 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 fea tures that communicate ?uid through the Well bore 203. The Working string 220 is coupled to the ?oW control device 223. The ?oW control device 223 may include a valve, a sliding sleeve, a port, and/or other features that communicate ?uid from the Working string 220 into the reservoir 205. The ?oW 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 ?oW control device 223. For example, ?uids may be injected by an open end of the Working string 220 Without using a ?oW 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 ?oW control device 223. The packers 224 may include mechanical packers, ?uid in?atable packers, sand packers, and/ or other types of packers. [0065] The instrument trucks 222 may include mobile vehicles, immobile installations, and/or other suitable struc tures. 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 instru ment 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 instru ment trucks 222 may include an injection control system that controls the ?oW of sealant and tracer materials into the reservoir 205 to achieve barriers 208 having desired proper ties. For example, the instrument trucks 222 may monitor and/or control the density, volume, ?oW rate, ?oW 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 differ ent 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.

[0066] 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 pro duction. 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 select ing and/or otherWise controlling ?uids pumped during the injection treatment. An injection control system (e.g., in the instrument trucks 222) may communicate With such equip ment to monitor and control the injection treatment.

[0067] 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 ?oW 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

Nov. 17, 2011

more viscous and/or solidify in the reservoir 205. The sealant 226 may impede or prevent ?uid ?oW in the resulting barrier 208, Which may alter ?uid ?oW 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 ?ll 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 seal ant material 226, may be mixed prior to injection, for example, in the pump trucks 221, in the Working string 220, in the ?oW 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 com bined in the reservoir 205, in the annulus, in the ?oW control device 223, in the Working string 220, in the pump trucks 221, and/or at any stage of forming the barrier 208. [0068] 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 modi?ed 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.

[0069] FIG. 3 is a diagram of an example treatment Well 300 that includes an injection system 330 injecting treatment ?uid 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 ?uid 110 into the subterranean reservoir 105. In some implementa tions, the injection system 330 injects treatment ?uids 310 into a reservoir to displace or sWeep resident hydrocarbon resources through the reservoir to a production Well.A barrier in the reservoir may in?uence the ?oW of the treatment ?uids 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 ?uids 310 and/or the hydrocarbons. Movement of the tracer in the res ervoir may be detected and analyZed to identify ?oW patterns in the reservoir.

[0070] 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 ?uids 310 and/or other materials to ?oW into the reservoir 305. Perforations 336 may be formed using shape charges, a perforating gun, and/or other tools.

[0071] The injection system 330 includes pump trucks 321, instrument trucks 322, Working string 332, ?oW 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 ?uid 310 to be injected into the reservoir 3 05. The treatment ?uid 3 10 may include Water, steam, and/ or other types of compressible and/ or incompressible ?uids that can promote migration of hydrocarbons through the reservoir 305. The pump trucks 321 are coupled to the Working string 332 to communicate treatment ?uid 310 into the Well bore 304. The Working string 332 is coupled to the ?oW control

Documents

(19) United States (12) Patent Application Publication (10) Pub. N0.2 US 2011…sep · 2015. 5. 27. · US 20110277996A1 (19) United States (12) Patent Application Publication (10)