WO2016011327A2 - Procédé de fracturation et de re-fracturation talon-pointe - Google Patents

Procédé de fracturation et de re-fracturation talon-pointe Download PDF

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Publication number
WO2016011327A2
WO2016011327A2 PCT/US2015/040865 US2015040865W WO2016011327A2 WO 2016011327 A2 WO2016011327 A2 WO 2016011327A2 US 2015040865 W US2015040865 W US 2015040865W WO 2016011327 A2 WO2016011327 A2 WO 2016011327A2
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WO
WIPO (PCT)
Prior art keywords
wellbore
location
treatment
perforation
well intervention
Prior art date
Application number
PCT/US2015/040865
Other languages
English (en)
Other versions
WO2016011327A3 (fr
Inventor
Yann Patrick KUHN DE CHIZELLE
Richard Christie
J. Ernest Brown
Bruno Lecerf
Michael Hayes KENISON
Tauna Leonardi
Original Assignee
Schlumberger Canada Limited
Services Petroliers Schlumberger
Schlumberger Holdings Limited
Schlumberger Technology B.V.
Prad Research And Development Limited
Schlumberger Technology Corporation
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Schlumberger Canada Limited, Services Petroliers Schlumberger, Schlumberger Holdings Limited, Schlumberger Technology B.V., Prad Research And Development Limited, Schlumberger Technology Corporation filed Critical Schlumberger Canada Limited
Publication of WO2016011327A2 publication Critical patent/WO2016011327A2/fr
Publication of WO2016011327A3 publication Critical patent/WO2016011327A3/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
    • E21B33/138—Plastering the borehole wall; Injecting into the formation
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • E21B43/261—Separate steps of (1) cementing, plugging or consolidating and (2) fracturing or attacking the formation

Definitions

  • the present disclosure is related in general to wellsite equipment such as oilfield surface equipment, downhole assemblies, coiled tubing (CT) assemblies, slickline and assemblies, and the like.
  • wellsite equipment such as oilfield surface equipment, downhole assemblies, coiled tubing (CT) assemblies, slickline and assemblies, and the like.
  • CT coiled tubing
  • Coiled tubing is a technology that has been expanding its range of application since its introduction to the oil industry in the 1960's. Its ability to pass through completion tubulars and the wide array of tools and technologies that can be used in conjunction with it make it a very versatile technology.
  • Typical coiled tubing apparatus includes surface pumping facilities, a coiled tubing string mounted on a reel, a method to convey the coiled tubing into and out of the wellbore, such as an injector head or the like, and surface control apparatus at the wellhead.
  • Coiled tubing has been utilized for performing well treatment and/or well intervention operations in existing wellbores such as, but not limited to, hydraulic fracturing, matrix acidizing, milling, perforating, coiled tubing drilling, and the like.
  • multiple stacked zones in vertical wells are typically completed by one of two methods.
  • the first method requires perforating, stimulating, and isolating each zone separately using composite bridge plugs. This method provides optimum stimulation for each zone, but many individual runs, or trips, into the wellbore require significant time and increase risk.
  • the second method is limited entry, in which multiple zones are opened at once and stimulated at high rates, and the method relies on perforation friction pressure for diversion. While limited entry stimulation reduces time and risk, it may result in decreased production of petroleum reserves, since multiple zones are stimulated simultaneously and effectiveness for each zone is not necessarily optimum.
  • toe to heel techniques In some other conventional stimulation treatments of multiple zones in deviated wellbores stimulation is conducted by so called toe to heel techniques.
  • perforation stimulation begins at the toe, or farthest point from the surface, and continues sequentially at each zone of interest, gradually moving closer to the surface until the last zone is stimulated proximate the kick off point from the vertical wellbore.
  • One problem encountered with toe to heel multiple stage stimulation is fluid loss into the formation as the toe region of the subterranean formation surrounding the wellbore commonly has higher porosity in comparison with the subterranean formation more proximate the heel area of the wellbore.
  • a method for performing a well intervention operation in a wellbore penetrating a subterranean formation of interest includes providing a heel to toe treatment tool, disposing the tool into the wellbore by conveying the tool via a conveyance such as coiled tubing, slickline, wireline, and the like.
  • the wellbore is cased and includes at least one opening, such as a frac-port, a slot, a perforation, and the like, proximate the subterranean formation.
  • the wellbore may be sealed adjacent the perforation and downhole from the at least one perforation, and at least one well intervention operation is performed through and adjacent the opening. Sealing of the wellbore may be achieved using any suitable device, such as, but not limited to, a settable packer.
  • the heel to toe treatment tool moving is then moved downhole to another casing opening, and the wellbore adjacent this second perforation is sealed downhole from this perforation. At least another well intervention operation performed adjacent this second opening.
  • methods according to the disclosure may also be used to perform intervention operations in an open hole wellbore where the heel to toe treatment tool is conveyed into and positioned within the open hole wellbore via a conveyance, the wellbore sealed downhole from this first position, and the operation conducted.
  • the seal is removed and the tool moved further downhole to a second position downhole to a second position, the wellbore sealed downhole from this second position and at least another well intervention operation performed adjacent this second position.
  • the positioning, sealing and intervention operation may be repeated as many times as required according to the overall treatment operation design, for either the cased wellbore or open hole wellbore scenarios, or even combination of cased and open hole wellbores.
  • methods further include determining a location in the wellbore for performing the at least one well intervention operation and the at least another well intervention operation.
  • the method may also further include monitoring the well intervention operation, and the monitoring may be determining the effectiveness of the well intervention operation.
  • the intervention operation is a treatment operation for treating the wellbore, and/or subterranean formation through which the wellbore is located.
  • the treatment operation may be a subterranean formation fracturing operation, or other operation such as matrix acidizing, gravel packing, and the like.
  • the method may be conducted at a location in the wellbore having a previously formed perforation(s), and in some instances, the location may be adjacent a portion of the subterranean formation which was previously fractured.
  • performing the at least one well intervention operation and performing the at least another well intervention operation includes flowing fluid from a wellbore surface to the treatment tool.
  • the fluid may be flowed along an annulus formed between coiled tubing (or other conveyance), the tool, and the wellbore. Alternatively, the fluid may be flowed through a flow path within the conveyance.
  • the fluids flowed may be any fluid required for the operation, including fluids such as a diversion fluid, chemical isolation fluid, fracturing fluid, and the like.
  • a method for performing a well intervention operation in a wellbore penetrating a subterranean formation of interest includes providing a heel to toe treatment tool, and disposing the tool in the wellbore utilizing a conveyance, where the wellbore has a plurality of treatment locations proximate the subterranean formation. At least a first treatment location and a second treatment location are determined; however, it is within the scope of the disclosure that any suitable number of treatment locations may be determined.
  • the wellbore adjacent the first treatment location is sealed, and at least one well intervention fluid operation is performed adjacent the first treatment location, after which, the first treatment location is sealed, such as with a diversion fluid, chemical isolation fluid, fracturing fluid, and the like, to prevent further fluid entry into the first treatment location.
  • the wellbore may be monitored to determine the effectiveness of the well intervention fluid operation and the sealing.
  • the tool is then moved downhole to a second treatment location, and the wellbore adjacent the second treatment location sealed. Another well intervention fluid operation is then performed adjacent the second treatment location.
  • the process may be repeated in as many sequences and locations required to conduct the overall treatment design, and in some cases, continue to the toe of the wellbore.
  • the tool may be moved downstream to an Nth treatment location, where N represents any number of further sequential treatments.
  • the wellbore is sealed adjacent the Nth treatment location, and an Nth well intervention fluid operation is conducted adjacent the Nth treatment location, after which the treatment location is sealed to prevent further fluid entry into the Nth treatment location.
  • the monitoring includes determining the effectiveness of the well intervention operation, while in some cases the monitoring includes determining the location in the wellbore for performing the at least one well intervention operation and the at least another well intervention operation.
  • the well intervention fluid operation may be a fracturing operation, or other type of subterranean formation operation.
  • the method may be conducted at a location in the wellbore having a previously formed perforation (s) or openings, and in some instances, the location may be adjacent a portion of the subterranean formation which was previously fractured.
  • Yet another aspect provides a method which includes providing a heel to toe treatment tool, and disposing the tool into a wellbore penetrating a subterranean formation utilizing coiled tubing, where the wellbore comprises a first perforation zone proximate the subterranean formation.
  • the wellbore adjacent the first perforation zone is sealed, and a portion of the subterranean formation proximate the first perforation zone is fractured.
  • the tool is then moved downhole deeper into the wellbore to a second perforation zone, the wellbore adjacent the second perforation zone is sealed, and a portion of the subterranean formation proximate the second perforation zone is fractured.
  • the fracturing of the portion of the subterranean formation proximate the first perforation zone and the portion of the subterranean formation proximate the second perforation zone may be monitored in some embodiments. Monitoring may include determining the effectiveness of the fracturing of the portion of the subterranean formation proximate the first perforation zone and the portion of the subterranean formation proximate the second perforation zone. In some method embodiments, at least one of the first perforation zone and the second perforation zone have a previously perforated location, and in some cases, at least one the first perforation zone and the second perforation zone comprises a previously fractured location.
  • the fracturing process may be repeated in as many sequences and locations required to conduct the overall fracturing design, and in some cases, continue to the toe of the wellbore. For example, after fracturing a portion of the subterranean formation proximate the second perforation zone, the heel to toe treatment tool may be moved downstream to an Nth perforation zone, the wellbore adjacent the Nth perforation zone sealed, and a portion of the subterranean formation proximate the Nth perforation zone fractured.
  • FIG.1 illustrates a general overview of a wellbore penetrating a subterranean formation with a coiled tubing conveyed treatment tool deployed therein, in accordance with an aspect of the disclosure, in a cross sectional view;
  • FIG.2 depicts three perforation cluster zones to be treated with a coiled tubing conveyed treatment tool, in accordance with some aspects of the disclosure, in a cross sectional view;
  • FIGS. 3A - 3D illustrate a treatment stage of a perforation cluster zone, according to an aspect of the disclosure, in a cross sectional view.
  • any references to "one embodiment” or “an embodiment” means that a particular element, feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment.
  • the appearances of the phrase “in one embodiment” in various places in the specification are not necessarily referring to the same embodiment.
  • the present disclosure concerns a heel to toe (HTT) broadband tool, or system indicated generally at 100.
  • the tool 100 may be disposed in a wellbore 102 penetrating a subterranean formation 103 zone of interest utilizing various surface equipment 104 at a surface 105 of the oilfield, as will be appreciated by those skilled in the art.
  • the wellbore 102 may have a substantially vertical portion 106 and a substantially deviated portion 108 (which is shown as a substantially horizontal portion) extending downhole (away from the oilfield surface 105) from the vertical portion 106, as depicted in Fig. 1 .
  • the deviated portion may be a portion of a wellbore extending from a kick off point of the vertical portion, and the deviated portion may be at any angle, or angles, relative the vertical portion.
  • the deviated portion is generally described and shown as a horizontal portion, herein.
  • a location of the horizontal portion 108 of the wellbore 102 adjacent the vertical portion 106 proximate a so called kick off point of the wellbore 102 is referred to as the heel 108a of the wellbore 102, and a portion of the horizontal portion 108 of the wellbore 102 extending away from the heel 108a (and further downhole or away from the oilfield surface 103) is referred to as the toe 108b of the wellbore.
  • the horizontal portion 108 of the wellbore 102 may have a plurality of perforations 1 10 disposed therein, when previous well intervention operations have been performed within the horizontal portion 108. While the term 'perforation' is used to illustrate some embodiments of the disclosure, it is within the scope and spirit of the disclosure that any opening in a casing, such as a frac-port, a slot, may be substituted for perforations as openings in casing, in the embodiments. Such perforations 1 10 may be referred to herein as existing perforations. One or more of the perforations 1 10 may be referred to herein as zones and/or clusters of the wellbore 100 that may be designated for treatment by the tool 100, as discussed in more detail below. In some aspects, a portion of, or even all of, the plurality of perforations 1 10 disposed in horizontal portion 108 of the wellbore 102, is formed during the present well intervention operation.
  • the perforations 1 10 may be or may have been formed via an abrasive jetting tool, a perforating gun assembly, pre-perforated casing, or any suitable device or apparatus, as will be appreciated by those skilled in the art.
  • abrasive jetting tool e.g., a perforating gun assembly
  • pre-perforated casing e.g., a perforating gun assembly
  • any suitable device or apparatus e.g., a desired fluid, such as a hydrocarbon or the like
  • a treatment fluid may be or may have been forced through the perforations 1 10 and into the formation at a high pressure, such as a pressure that is equal to or greater than a fracture initiation pressure of the formation, in order to fracture the formation such that the desired fluid may be released from the formation and may then be flowed out the perforations 1 10, through the wellbore 102 and to the wellbore surface.
  • formation stimulation involves pumping an acid through the perforations 1 10 and into the formation at sufficient pressure to perform matrix acidizing of the formation.
  • the stimulation may be a combined acidizing / fracturing operation.
  • An embodiment of the tool and/or system 100 may be deployed and/or conveyed into the wellbore 102 with a conveyance 1 12.
  • the conveyance 1 12 may include coiled tubing (CT)
  • the surface equipment 104 may include a coiled tubing reel, a coiled tubing injector head or the like, and surface control apparatus at the wellhead.
  • the tool and/or system 100 may include a settable packer 1 14 or a similar wellbore isolation device, a tool 1 16 at a distal end of the tool 100, such as, but not limited to, a cleanout nozzle, an abrasive jetting tool, a cup packer, a sail, or the like, and a treatment nozzle 1 18 for placing wellbore treatment fluid or the like in the wellbore 102.
  • a tool 1 16 at a distal end of the tool 100, such as, but not limited to, a cleanout nozzle, an abrasive jetting tool, a cup packer, a sail, or the like
  • a treatment nozzle 1 18 for placing wellbore treatment fluid or the like in the wellbore 102.
  • Other tools and/or devices may be utilized as part of the system 100, as discussed in more detail hereinbelow.
  • a coiled tubing deployment system may be run into the wellbore to determine from which perforations the formation 103 is producing, such as by, but not limited to, utilizing a fiber optic enabled coiled tubing assembly having a fiber optic tether deployed in the interior of the coiled tubing, and subsequently utilized to performed at least distributed temperature surveys (DTS) of the wellbore.
  • DTS distributed temperature surveys
  • the DTS applications may provide an indication to an operator which of the perforations 1 10 and/or zones or clusters of the wellbore 102 is producing and/or which of the perforations 1 10 and/or zones of the wellbore 102 is not producing. Based on this information, it may be desirable to attempt to re-stimulate and/or re-treat the perforations 1 10 of the wellbore 102 and adjacent formation in order to increase production from the wellbore 102.
  • the system 100 is shown deployed, schematically, in a wellbore 102, which may be the vertical portion 106, the horizontal portion 108, or both portions.
  • An arrow 120 indicates an uphole direction and an arrow 122 indicates a downhole direction.
  • the tool and/or system 100 is deployed in the wellbore 102 and the packer 1 14 is extended to form a seal with an interior surface of the wellbore 102, which may be an interior surface of a wellbore casing, open hole wellbore wall, or the like.
  • the tool 100 and coiled tubing 1 12 define an annulus 124 between an exterior surface of the tool 100 and coiled tubing 1 12 and the interior surface of the wellbore 102.
  • the packer 1 14 is set in a location where the packer 1 14 isolates a zone or cluster of perforations 1 10a from other zones or clusters 1 10b, 1 10c in the wellbore.
  • any or all of the zones or clusters 1 10a, 1 10b, and 1 10c may be previously formed perforations, zones, or clusters.
  • the cluster and/or zone 1 10a may be a single perforation, a single perforation interval, or a cluster of perforations.
  • the tool and/or system 100 may or may not be anchored.
  • a fracturing and/or treatment fluid is flowed from the surface equipment 104 and through the annulus 124 at a suitable pressure for fracturing or other treatment.
  • the packer 1 14 seals the wellbore 102, as discussed above, and thus the fluid is directed to and through the perforations 1 10a.
  • the fluid delivered under pressure may be introduced into the formation (such as the formation 103) surrounding the wellbore 102 at a pressure that is greater than a fracture initiation pressure of the formation, thereby forming fractures 126 in the formation through the perforations 1 10a.
  • the fracturing and/or treatment fluid flow through the annulus 124 has stopped and a sealing and/or recirculating operation commences.
  • a second treatment fluid is flowed from the surface equipment 104 and through the interior of the coiled tubing 1 12 and out the treatment nozzle 1 18.
  • the second treatment fluid displaces any fracturing fluid and flows into the fractures 126 through the perforations 1 10a.
  • the second treatment fluid may be a chemical isolation fluid, a diverter or similar type treatment fluid that contains particles that expand and/or otherwise in any practical way, form a seal 128 upon entry into the perforations 1 10a and/or fractures 126, thereby preventing further fluid entry into the perforations 1 10a and/or fractures 126.
  • the second treatment fluid which may be a chemical isolation fluid, a diverter or similar type treatment fluid, may be flowed from the surface equipment 104 to the perforations 1 10a along the annulus 124.
  • the second treatment fluid generally includes a base fluid and any suitable particles which adequately seal the perforations when placed therein, to avoid loss of treatment fluid into the subterranean formation through perforations 1 10a, when treatment is conducted for perforations, such as 1 10b and/or 1 10c.
  • the second treatment fluid may include particles that expand and/or otherwise form a seal.
  • the particles forming such a sealing pack include two or more size modality particles, and further including a water removal constituent.
  • Example and non-limiting water removal constituents include fibers (which may be hydroscopic, or may just provide support from particle movement occurring), a hydroscopic material, and/or a water absorbent material (e.g. bentonite, a polymer, etc.).
  • Example and non-limiting materials include coated materials, for example a material that is not active to absorb water until placed across the zone to be isolated, and in response to time, temperature, pressure, and/or a reaction the coating is removed and water absorption or other removal commences.
  • the water removal and/or particle pack fixing material e.g. fibers
  • the particle pack will degrade at a later time, allowing the particle pack to re-fluidize and enhance cleanup.
  • the degradable particles transform from a solid to a liquid state.
  • the particles in the second treatment fluid may be selected such that the dry blend of particles will have a maximum packing volume fraction (i.e., the particles pack with minimum void space between them). This may be accomplished by choosing particles with different particle size distributions with the average particle size of each distribution being 2 to 10 times smaller than the average particle size of the next larger distribution. The particles are held in suspension because of hindered settling.
  • One or more particle size distributions may comprise degradable particles so that the pack will have a high permeability after placing it downhole. If degradable particles are not present the smaller particles will block the void spaces in the pack thereby decreasing the permeability.
  • the second treatment fluid includes particles formed of an elastomeric swellable material adapted to swell when in contact with water and/or oil.
  • materials that swell upon contact with hydrocarbon fluid include, but are not necessarily limited to, natural rubber, nitrile rubber, hydrogenated nitrile rubber, acrylate butadiene rubber, poly acrylate rubber, butyl rubber, brominated butyl rubber, chlorinated butyl rubber, chlorinated polyethylene, neoprene rubber, styrene butadiene copolymer rubber, sulphonated polyethylene, ethylene acrylate rubber, epichlorohydrin ethylene oxide copolymer, ethylene- propylene-copolymer (peroxide crosslinked), ethylene-propylene-copolymer (sulphur crosslinked), ethylene-propylene-diene terpolymer rubber, ethylene vinyl acetate copolymer, fluoro rubbers, fluoro silicone rubber, silicone
  • the swellable material may be adapted to swell upon contact with water.
  • water-swellable material may be selected from rubbers based on acrylonitrile butadiene (NBR), hydrogenated nitrile butadiene (HNBR), acrylonitrile butadiene carboxy monomer (XNBR), fluorinated hydrocarbon (FKM), perfluoroelastomers (FFKM), tetrafluoroethylene/propylene (TFE/P), or ethylene propylene diene monomer (EPDM).
  • NBR acrylonitrile butadiene
  • HNBR hydrogenated nitrile butadiene
  • XNBR acrylonitrile butadiene carboxy monomer
  • FKM fluorinated hydrocarbon
  • FFKM perfluoroelastomers
  • TFE/P tetrafluoroethylene/propylene
  • EPDM ethylene propylene diene monomer
  • the material suitably is a matrix material where a compound soluble in water is incorporated in the matrix material in a manner that the matrix material substantially prevents or restricts migration of the compound out of the swellable seal and allows migration of water into the swellable seal by osmosis so as to induce swelling of the swellable seal upon migration of the water into the swellable seal.
  • the compound may include a salt, for example, at least 20 weight % salt based on the combined weight of the matrix material and the salt, or in some cases, at least 35 weight % salt based on the combined weight of the matrix material and the salt.
  • the second treatment fluid includes a water absorbing composition containing a particle having a core of a water-swelling material and a coating substantially surrounding the core that temporarily prevents contact of water with the water-swelling material.
  • the coating may be formed from at least one of (1 ) a layer or layers of water degradable material and (2) a non- water-degradable, non-water absorbent layer or layers of encapsulating material.
  • the water-swelling material is at least one of a clay and a superabsorbing material.
  • the clay may be selected from bentonite, montmorillonite, smectite, nontronite, beidellite, perlite and vermiculite clays and combinations of these, and the superabsorbing material is selected from polymers and copolymers of acrylate, acrylic acid, amide, acrylamide, saccharides, vinyl alcohol, urethane, and combinations of these materials.
  • the water degradable material may be solid polymer acid precursor, for example a polylactic acid and/or polyglycolic acid coating
  • the core may further contain a weighting material, for example a material selected from silicates, aluminosilicates, barite, hematite, ilmenite, manganese tetraoxide, manganosite, iron, lead, aluminum and combinations of these.
  • the core includes an inner core of particulate material with an outer layer of the water absorbent material formed around the particulate material, and the water-swelling material is a superabsorbent material that has been surface cross-linked to delay further swelling, and the water- swelling material is capable of absorbing at least the water-swelling material's weight of water.
  • this concept can be extended to a brine swellable elastomer added to brine or oil water based high solid content fluid.
  • brine swellable elastomers include butadiene based polymers and copolymers such as styrene butadiene rubber (SBR), styrene butadiene block copolymers, styrene isoprene copolymer, acrylate elastomers, neoprene elastomers, nitrile elastomers, vinyl acetate copolymers and blends of EVA, polyurethane elastomers, maleic acid grafted styrene butadiene elastomers and acrylic acid grafted elastomers.
  • SBR styrene butadiene rubber
  • styrene butadiene block copolymers styrene isoprene copolymer
  • the second treatment fluid contains hydrogel particles.
  • a hydrogel is defined as a gel containing water as the dispersion medium in which either a cross-linked or uncrosslinked network of hydrophilic polymer or colloidal particles are dispersed that bind and immobilize water molecules.
  • Some exemplary organic polymers suitable for use as hydrogel particles include, without limitation, water swellable polymers, water soluble polymers, or acrylic acid-based polymers, and combinations thereof.
  • Nonlimiting examples of water swellable polymers suitable for use in accordance with disclosure include pre-crossl inked polymers, such as starch, polyacrylamide, polymethacrylate, or combinations thereof. In an embodiment such polymers are dry or substantially free of a liquid component.
  • the water swellable polymer is a superabsorbent.
  • superabsorbents include sodium (alkyl)acrylate-based polymers having three dimensional, network-like molecular structures.
  • the polymer chains are formed by the reaction/joining of millions of identical units of acrylic acid monomer, which have been substantially neutralized with sodium hydroxide.
  • Crosslinking chemicals tie the chains together to form a three- dimensional network, enabling the superabsorbents to absorb water or water-based solutions into the spaces in the molecular network, and thus forming a gel and locking up the liquid.
  • the hydrogel particles include water soluble biopolymers and crosslinkers.
  • the hydrogels may be polysaccharides or polysaccharide derivatives such as hydroxyl ethyl, hydroxypropyl, carboxymethyl, carboxymethyl hydroxyl ethyl, and grafted polymers such as 2-acrylamido-2- methyl- propane sulfonic grafted, acrylonitrile grafted, acrylamide grafted, acrylic acid grafted, vinyl phosphonic acid grafted or vinyl sulfonic acid grafted polymers.
  • suitable polysaccharides include without limitation alginic acid and its salts, pectinates, chitosan and guar.
  • Inorganic materials suitable as crosslinkers for forming hydrogels for use in some embodiments of the disclosure include, without limitation, borate salts, phosphoryl chloride, main group or transition metal salts such Group 2 and Group 13 main group metal salts and Group 4, 6 and Group 8 transition metal salts, or combinations thereof.
  • Suitable organic crosslinkers include 3-chloropropylene oxide (epichlorohydrin), genepin, glyoxal, glutaraldehyde and dichlorodialkylsilanes.
  • particles included in the second treatment fluids divert fluids from one portion of the formation to another, or to isolate one portion of the formation from another.
  • the particles may be any shape or size, including, but not limited to, shapes such as spherical, fiber-like, ovoid, ribbons, and the like.
  • the particles may have a mean particle diameter in the range of from a lower limit of about 5 microns, 25 microns, 50 microns, 75 microns, 100 microns, 150 microns, 200 microns, 250 microns, 300 microns, 350 microns, 400 microns, 450 microns, 500 microns to an upper limit of about 8000 microns, 7000 microns, 6000 microns, 5000 microns, 4000 microns, 3000 microns, 2000 microns, 1000 microns, 500 microns, 400 microns, 300 microns, 250 microns, 200 microns, 150 microns, or 100 microns, and the mean particle diameter may range from any lower limit to any upper limit and encompass any subset between the upper and lower limits.
  • a preferred mean particle diameter for the particles may be between about 100 microns to 250 microns, another preferred mean particle diameter for the particles may be about 150 microns or greater.
  • the particles will be monomodal and relatively uniform in size, while in other embodiments the particles may be multimodal.
  • U.S. Pat. No. 8,905,133 incorporated in its entirety herein by reference hereto, describes a blends of amounts of pluralities of particulate sizes useful in some embodiments of the disclosure for diverting fluids from one portion of the formation to another, or to otherwise isolate one portion of the formation from another.
  • the base fluid component of the second treatment fluid may be any liquid component suitable for transporting solids that is commonly included in subterranean applications, including, but not limited to, water, brines, viscosified fluids, foams, aqueous gels, viscoelastic surfactant gels, emulsions, combinations thereof, and other fluids suitable for transporting solids.
  • the base fluid component includes an aqueous gel
  • the aqueous gel generally comprises water and a gelling agent.
  • the aqueous gel further may comprise water, a gelling agent, and a crosslinking agent that crosslinks at least a portion of the molecules of the gelling agent further increasing the viscosity of the fluid, which further may affect the base fluid's ability to suspend solids.
  • the base fluid component is an emulsion
  • the emulsion may include one or more immiscible liquids.
  • the emulsion may include an aqueous gel and a liquefied, normally gaseous fluid (e.g., carbon dioxide).
  • normally gaseous fluid e.g., carbon dioxide
  • the base fluid component may be present in the in an amount in the range of from about 40% to about 99% by volume of the fluid, when measured at the surface, prior to placement of the second treatment fluid into the subterranean formation.
  • an excess amount of the second treatment fluid is recirculated in the wellbore using the coil tubing, or recirculated through the annulus formed between the conveyance and wellbore wall, in order to ensure the next zone being treated will not immediately be contaminated by any excess of the second treatment fluid.
  • the packer 1 14 is unset and the system and/or tool 100 is moved in the downstream direction 122.
  • the packer 1 14 is again extended to form a seal with the interior surface of the wellbore 102, which may be an interior surface of a wellbore casing or the like.
  • the tool 100 and coiled tubing 1 12 again define the annulus 124 between an exterior surface of the tool 100 and coiled tubing 1 12 and the interior surface of the wellbore 102.
  • the packer 1 14 is now set in a location where the packer 1 14 isolates the zone or cluster of perforations 1 10b from the downstream zones or clusters 1 10c in the wellbore and the seal 128 formed by the treatment fluid in the fractures 126 isolates the perforations 1 10a.
  • fracturing and/or treatment fluid may be flowed through the annulus 124 and into the perforations 1 10b due to the seals formed by the packer 1 14 and the seals 128 of the treatment fluid and the formation fractured, as discussed with respect to Figure 3B.
  • Treatment fluid may then be flowed through the perforations 1 10b and into the fractures as in Figure 3C and the system and/or tool 100 may be moved again in the downhole direction 122 for as many times as there are zones and/or clusters desired to be treated.
  • stimulation of the subterranean formation is conducted using coiled tubing as a conveyance for the tool which delivers the second treatment fluid and treating the formation.
  • coiled tubing as a conveyance for the tool which delivers the second treatment fluid and treating the formation.
  • One such technique may be similar to, or like the CoilFRACTM service available from Schlumberger Technology Corporation, Houston, Texas, which combines coiled tubing CT and selective fracturing technology to enable the treatment of multiple zones in one trip, into new or existing wellbores.
  • each zone is perforated conventionally in one wellsite visit, and in existing wells, new zones within the wellbore may be, or may not be, conventionally perforated as well.
  • the coiled tubing is then deployed into the wellbore with a straddle tool bottom hole assembly.
  • the bottom zone is straddled, and the fracturing fluid is pumped through the CT string. Residual proppant is reverse-circulated out of the wellbore, and a second treatment fluid is pumped through the coiled tubing to seal the perforations through which the fracturing fluid was just pumped.
  • the tool is moved to the next zone away from the heel toward the toe, where the process is repeated. Through this process, each zone is individually stimulated, and only one run into the wellbore is required.
  • Such approach may enable customizing the fracture stimulation for each targeted zone, accounting for varying stress contrast, porosity, permeability, and fracture gradients. Such customization may allow for optimum production while maximizing recoverable petroleum reserves from each zone.
  • decoupling the fracturing operation from the perforating operation streamlines the completion process with fewer trips into the wellbore.
  • Some further embodiments of the disclosure include methods of fracturing a subterranean formation where coiled tubing is inserted into a wellbore, and a first solution comprising a viscosifying polymer and proppant is pumped into the annular space of the wellbore.
  • a second aqueous solution including at least a crosslinking agent (and other suitable chemicals or additives) capable of crosslinking the viscosifying polymer is provided.
  • a coiled tubing string having interior and exterior surfaces is provided, the coiled tubing string forming on part of its exterior surface an annular space within the wellbore, the coiled tubing string having a proximal end located near the ground surface and a distal end located within the wellbore in the subterranean formation and proximate to the formation to be treated.
  • the method further involves pumping into the annular space of the wellbore the first aqueous solution and pumping into the coiled tubing string the second aqueous solution.
  • the first and second aqueous solutions are combined, which is followed by crosslinking of the galactomannan gum to form a crosslinked fracturing fluid, for fracturing the subterranean formation.
  • another treatment fluid is pumped through the coiled tubing to seal and isolate the perforations through which the fracturing fluid entered the subterranean formation, and the distal end of the coiled tubing is moved further away from the surface to fracture another zone in the wellbore and adjacent formation.
  • the pumping of the crosslinker may be interrupted briefly for a length of time sufficient to make very accurate measurements of the downhole pressure in the coiled tubing string.
  • the method may be implemented with a cable inserted in the coiled tubing and connected to a pressure sensor located downhole. In such cases, the downhole pressure is continuously and precisely determined. When there is no cable, the downhole pressure can be estimated or calculated from the surface pressure measurement in the coiled tubing corrected for the friction losses when the crosslinker fluid is pumped and optionally measured more accurately by stopping the flow in the coiled tubing altogether. It is also possible to determine pressure in the dynamic state while fluid is flowing.
  • a monitoring system and/or method may be used during the operation.
  • a monitoring system may be used to identify and/or locate the clusters and/or zones 1 10 to be treated and to monitor the treatment as well as validate the effectiveness of the treatment.
  • the monitoring may be accomplished through the use of data for ascertaining pressure, flow rate, temperature, and/or degree of vibration.
  • the monitoring system may be utilized to determine if the first re-fracturing or initial fracturing treatment is effective or ineffective, such that the cluster and/or zone 1 10 can be re-fractured and the isolation fluid be re-applied, as the process can be repeated until the desired treatment, resultant flow rate, and/or other properties of the perforations 1 10 is achieved.
  • the monitoring device may monitor the depth to locate the desired zone to be re-fractured or initially fractured, as well as monitoring pressure in the desired zone to ensure that the chemical isolation is effective.
  • the monitoring device may monitor the downhole pressure of the packer 1 14 to ensure that the seal formed by the packer is adequate to ensure fracture fluid is not leaking into other zones, such as 1 10b or 1 10c, when zone 1 10a is being treated.
  • the monitoring device may also be used in some cases, to predict or detect screen out conditions so that immediate actions may be taken to prevent screen out.
  • the monitoring device may be used to monitor fluid flow rate to ensure that the packer element 1 14 has maintained integrity, or if flow rate of fracturing fluid to the downhole side of the packer element 1 14 exists, which may be indicative of fracturing fluid leakage into other downhole zones.
  • the monitoring device may also be used to validate fracture 126 growth, such techniques as downhole pressure measurements, microseismic measurements where the conveyance includes acoustic sensors, and the like.
  • the monitoring may include use of sensors to monitor and optimize fracturing diversion/movements from one perforated interval/cluster to the next.
  • the monitoring system and/or device may be used for downhole monitoring techniques such as, distributed temperature surveys (DTS), casing collar locators (CCL) position, pressure measurement, temperature measurement, vibration measurement, and/or flow rate measurements.
  • the monitoring system and/or device may monitor from chemical isolation fluid effectiveness from the surface by increasing fluid pressuring in the annulus after the chemical isolation fluid is deployed and the isolation sealing device 1 14 is engaged, and measuring the pressure and/or change in pressure.
  • the monitoring device may include a fiber optic tether deployed in an interior flow path of the coiled tubing 1 12, which may be subsequently utilized for distributed measurements such properties as, but not limited to, temperature, pressure, vibration, strain, seismic waves, and the like.
  • the monitoring device and/or system may be utilized to monitor events and/or data within the wellbore and/or within the fractures 126.
  • the measurements including the distributed measurements, may be made while pumping the chemical isolation fluid to verify that diversion and/or formation of the seals 128 is occurring, and/or to verify and/or validate the seal 128 has been adequately set.
  • fracturing fluid may not be flowed to the perforations 1 10a as in Figure 3B, but rather treatment fluid is flowed from the surface equipment 104, through the interior of the coiled tubing 1 12, out of the treatment nozzle 1 18, and into the perforations 1 10a, which may or may not have existing fractures.
  • the zone and/or cluster 1 10a is thereby isolated and the system and/or tool 100 may be moved in the downstream direction 122. This may be repeated as often as necessary, as those skilled in the art will appreciate, as not all zones and/or clusters 1 10 may require fracturing and/or treatment, or may not be desired to be fractured and/or treated.
  • the chemical isolation fluid may be replenished at each zone and/or cluster 1 10, such as if any particular perforation interval 1 10 did not require isolation, or in those instances where premature degradation of the chemical isolation fluid is detected by the monitoring system.
  • the chemical isolation fluid may be recirculated out of the wellbore 102 through the coiled tubing 1 12 or up the annulus 124 prior to moving the tool and/or system 100 to the next cluster and/or zone 1 10.
  • the tool and/or system 100 allows for recirculation and/or cleanout of the well 102 in the case of screen out or the like. Recirculation and/or cleanout may be achieved by flowing fluid back through the coiled tubing 1 12 or through the annulus 124.
  • the system and/or tool 100 may be utilized to perform a coiled tubing deployed, fracturing or re-fracturing method in order to re-stimulate existing perforations, zones, and/or clusters in wellbores, such as the wellbore 102, and/or perforations 1 10 and/or zones and/or clusters that do not have a sleeve-based re- fracturing completion in the wellbore.
  • the system and/or tool 100 may be utilized to create new perforations and stimulate the new clusters and/or zones within the wellbore 102.
  • a method embodiment may provide the isolation of existing zones and/or clusters of perforations 1 10 where production is reduced or depleted.
  • the tool 100 and/or method provides the ability to apply a chemical isolation fluid to predefined perforation zones and/or clusters 1 10, which provides improved fracturing control and fluid efficiency.
  • an embodiment of a method and/or system 100 will provide an ability to decrease the cluster spacing in old wells by allowing new clusters to be perforated for fracturing.
  • the system 100 and/or method will be deployed from the heel 108a of the well to the toe 108b rather than the conventional toe 108b to heel 108a configuration and/or deployment.
  • the tool, system, and/or method disclosed herein may also include other components or steps.
  • the method of deployment may be via coiled tubing, wireline, slickline, or similar and the method and/or tool may be performed from the heel of the well to the toe.
  • the tool and/or system 100 comprises a device that removes or eliminates the chemical isolation fluid, such as by increasing the temperature or via chemical removal or via mechanical removal of the chemical isolation fluid.
  • a jetting device such as an abrasive jetting device, or other perforating device, may be deployed with the system and/or tool 100 such that new zones may be created and then fractured and/or treated.
  • a jetting device such as an abrasive jetting device
  • new perforations such as the perforations 1 10 may be created in the wellbore 102 prior to starting the sequence of isolating, fracturing or otherwise treating, and/or sealing, as noted in Figures 3A-3D.
  • Such an embodiment may create new openings or perforations 1 10, which may be desirable when re-fracturing a wellbore 102 in order to connect to zones and/or formations bypassed in the original treatment. Such an embodiment may allow the new perforations 1 10 to be formed in a single trip without having to bring the system and/or tool 100 to the surface 103 prior to performing the pumping and fracturing operation.
  • the tool 100 may further include at the bottom of the conveyance, a device or flow path to allow fluid recirculation and/or jetting to remove wellbore debris, which may have been generated from an earlier treated zone during the wellbore intervention.
  • system and/or tool 100 may further include a device for extended reach applications where assistance is needed to deploy the system and/or tool 100 further downhole (such as further toward the toe portion 108b of the horizontal portion 108).
  • a pump down system as a bullnose geometry or cup allowing pump down (such as in the case of a wireline tool), or an extended reach method, such as a vibrating device may be utilized for such extended reach applications.
  • a dual isolation device may be a part of the system and/or tool 100, where the chemical isolation fluid may be applied and/or squeezed directly into the cluster and/or zone 1 10, rather than bullheading the chemical isolation fluid from the surface 103 to the cluster and/or zone 1 10.
  • the system and/or tool 100 may utilize a straddle packer or the like for isolating the wellbore 102.
  • the system and/or tool 100 comprises a device (i.e. progressive cavity pump, check valve, etc.) which may allow pressure built up in the toe region 108b to bleed back to the heel region 108a to prevent fluid lock.
  • a device i.e. progressive cavity pump, check valve, etc.
  • the tool and/or system 100 may be anchored during treatment. The anchoring may be accomplished by utilizing an anchoring mechanism or by holding back the coiled tubing 1 12.
  • each of the clusters and/or zones 1 10 within the wellbore 102 may be sealed entire wellbore with the chemical isolation fluid.
  • the seals 128 of specific clusters and/or zones 1 10 may then be melted, dissolved, displaced, or otherwise removed to enable treatment of the specific cluster and/or zone 1 10.
  • first, second, third, etc. may be used herein to describe various elements, components, regions, layers and/or sections, these elements, components, regions, layers and/or sections should not be limited by these terms. These terms may be only used to distinguish one element, component, region, layer or section from another region, layer or section. Terms such as “first,” “second,” and other numerical terms when used herein do not imply a sequence or order unless clearly indicated by the context. Thus, a first element, component, region, layer or section discussed below could be termed a second element, component, region, layer or section without departing from the teachings of the example embodiments.
  • Spatially relative terms such as “inner,” “outer,” “beneath,” “below,” “lower,” “above,” “upper,” and the like, may be used herein for ease of description to describe one element or feature's relationship to another element(s) or feature(s) as illustrated in the figures. Spatially relative terms may be intended to encompass different orientations of the device in use or operation in addition to the orientation depicted in the figures. For example, if the device in the figures is turned over, elements described as “below” or “beneath” other elements or features would then be oriented “above” the other elements or features. Thus, the example term “below” can encompass both an orientation of above and below. The device may be otherwise oriented (rotated 90 degrees or at other orientations) and the spatially relative descriptors used herein interpreted accordingly.

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Abstract

L'invention concerne un procédé pour effectuer une opération d'intervention sur puits dans un puits de forage pénétrant dans une formation souterraine d'intérêt, qui consistant à utiliser un outil de traitement talon-pointe, à disposer l'outil dans le puits de forage par acheminement de l'outil par l'intermédiaire d'un tubage hélicoïdal, et le puits de forage comprend au moins une perforation à proximité de la formation souterraine. Le puits de forage est fermé hermétiquement de manière adjacente la perforation et au fond de trou depuis la ou les perforations, et au moins une opération d'intervention sur puits est effectuée adjacente à la perforation. L'étanchéité du puits de forage peut être réalisée à l'aide de tout dispositif approprié, tel que, mais sans s'y limiter, une garniture d'étanchéité réglable. L'outil de traitement talon-pointe est ensuite déplacé en fond de trou jusqu'à une autre perforation, et le puits de forage adjacent à cette seconde perforation est scellé en fond de trou depuis cette perforation.
PCT/US2015/040865 2014-07-17 2015-07-17 Procédé de fracturation et de re-fracturation talon-pointe WO2016011327A2 (fr)

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Cited By (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
NL2016185A (en) * 2016-01-29 2017-08-02 Halpa Intellectual Properties B V Method for counteracting land subsidence in the vicinity of an underground reservoir.
US10280698B2 (en) 2016-10-24 2019-05-07 General Electric Company Well restimulation downhole assembly
CN110939422A (zh) * 2020-01-06 2020-03-31 中国石油集团川庆钻探工程有限公司长庆井下技术作业公司 一种具有射孔子簇的水平井分段多簇限流压裂方法
CN113530517A (zh) * 2021-09-17 2021-10-22 中煤科工集团西安研究院有限公司 一种联合分段压裂装置、异步双路抽采系统及方法
US11293280B2 (en) * 2018-12-19 2022-04-05 Exxonmobil Upstream Research Company Method and system for monitoring post-stimulation operations through acoustic wireless sensor network

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Publication number Priority date Publication date Assignee Title
DZ3387A1 (fr) * 2000-07-18 2002-01-24 Exxonmobil Upstream Res Co Procede pour traiter les intervalles multiples dans un trou de forage
US20040040707A1 (en) * 2002-08-29 2004-03-04 Dusterhoft Ronald G. Well treatment apparatus and method
US7278486B2 (en) * 2005-03-04 2007-10-09 Halliburton Energy Services, Inc. Fracturing method providing simultaneous flow back
US8887803B2 (en) * 2012-04-09 2014-11-18 Halliburton Energy Services, Inc. Multi-interval wellbore treatment method
US9279306B2 (en) * 2012-01-11 2016-03-08 Schlumberger Technology Corporation Performing multi-stage well operations

Cited By (8)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
NL2016185A (en) * 2016-01-29 2017-08-02 Halpa Intellectual Properties B V Method for counteracting land subsidence in the vicinity of an underground reservoir.
WO2017131520A1 (fr) * 2016-01-29 2017-08-03 Halpa Intellectual Properties B.V. Procédé permettant de contrecarrer un affaissement de terrain au voisinage d'un réservoir souterrain
US10280698B2 (en) 2016-10-24 2019-05-07 General Electric Company Well restimulation downhole assembly
US11293280B2 (en) * 2018-12-19 2022-04-05 Exxonmobil Upstream Research Company Method and system for monitoring post-stimulation operations through acoustic wireless sensor network
CN110939422A (zh) * 2020-01-06 2020-03-31 中国石油集团川庆钻探工程有限公司长庆井下技术作业公司 一种具有射孔子簇的水平井分段多簇限流压裂方法
CN110939422B (zh) * 2020-01-06 2022-03-11 中国石油天然气集团有限公司 一种具有射孔子簇的水平井分段多簇限流压裂方法
CN113530517A (zh) * 2021-09-17 2021-10-22 中煤科工集团西安研究院有限公司 一种联合分段压裂装置、异步双路抽采系统及方法
CN113530517B (zh) * 2021-09-17 2021-12-14 中煤科工集团西安研究院有限公司 一种联合分段压裂装置、异步双路抽采系统及方法

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