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WO2011136678A1 - Placement d'agent de soutènement hétérogène - Google Patents

Placement d'agent de soutènement hétérogène Download PDF

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Publication number
WO2011136678A1
WO2011136678A1 PCT/RU2010/000207 RU2010000207W WO2011136678A1 WO 2011136678 A1 WO2011136678 A1 WO 2011136678A1 RU 2010000207 W RU2010000207 W RU 2010000207W WO 2011136678 A1 WO2011136678 A1 WO 2011136678A1
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WO
WIPO (PCT)
Prior art keywords
proppant
polyelectrolyte
fluid
polymer
formation
Prior art date
Legal status (The legal status 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 status listed.)
Ceased
Application number
PCT/RU2010/000207
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English (en)
Inventor
Anatoly Vladimirovich Medvedev
Sergey Mikhailovich Makarychev-Mikhailov
Evgeny Borisovich Barmatov
Trevor Hughes
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Schlumberger Canada Ltd
Services Petroliers Schlumberger SA
Schlumberger Technology BV
Schlumberger Holdings Ltd
Prad Research and Development Ltd
Original Assignee
Schlumberger Canada Ltd
Services Petroliers Schlumberger SA
Schlumberger Technology BV
Schlumberger Holdings Ltd
Prad Research and Development Ltd
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Filing date
Publication date
Application filed by Schlumberger Canada Ltd, Services Petroliers Schlumberger SA, Schlumberger Technology BV, Schlumberger Holdings Ltd, Prad Research and Development Ltd filed Critical Schlumberger Canada Ltd
Priority to US13/642,557 priority Critical patent/US20130056213A1/en
Priority to MX2012012330A priority patent/MX2012012330A/es
Priority to CA2797294A priority patent/CA2797294A1/fr
Priority to RU2012150663/03A priority patent/RU2544943C2/ru
Priority to PCT/RU2010/000207 priority patent/WO2011136678A1/fr
Publication of WO2011136678A1 publication Critical patent/WO2011136678A1/fr
Anticipated expiration legal-status Critical
Priority to US14/620,979 priority patent/US20150152321A1/en
Ceased legal-status Critical Current

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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
    • E21B43/267—Methods for stimulating production by forming crevices or fractures reinforcing fractures by propping
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/62—Compositions for forming crevices or fractures
    • C09K8/66—Compositions based on water or polar solvents
    • C09K8/68—Compositions based on water or polar solvents containing organic compounds
    • C09K8/685—Compositions based on water or polar solvents containing organic compounds containing cross-linking agents
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
    • C09K2208/08—Fiber-containing well treatment fluids

Definitions

  • the present invention relates to reservoir stimulation by hydraulic fracturing. More particularly it relates to methods of heterogeneous proppant placement (HPP) in fractures, which increases their conductivity and enhances fluid production.
  • HPP is achieved by formation of proppant clusters in situ in the fracture due to polymer gel phase transitions or polymer gel chemical transformations.
  • One embodiment of the invention is a method of inducing proppant aggregation in a hydraulic fracture including the steps of (1 ) formulating a proppant carrier fluid viscosified by a first polymer gel that can undergo syneresis; (2) injecting a slurry of the fluid and proppant; and (3) triggering gel syneresis.
  • the fluid may contain fibers and at least a portion of the proppant may be resin coated.
  • the polymer gel is crosslinked, for example the gel is a borate crosslinked polymer gel, and the syneresis is triggered by incorporation of a multivalent cation in the gel.
  • the multivalent cation is a cation of a metal selected for example from Ca, Zn, Al, Fe, Cu, Co, Cr, Ni, Ti, Zr and mixtures of these.
  • the cation is incorporated for example by dissolution or by slow dissolution, for example of a salt, an oxide or a hydroxide of the cation.
  • the cation may optionally be in the form of a hydroxide or an in situ formed hydroxide when it causes the syneresis.
  • the syneresis is caused by overcrosslinking.
  • the overcrosslinking may be delayed for example by a crosslink delay agent, or may be induced for example by an encapsulated crosslinker, a slowly dissolvable crosslinker, or a temperature-activated crosslinker.
  • the syneresis is caused by including in the fluid, in addition to the polymer in the first polymer gel, a second polymer and a delayed crosslinker for the second polymer.
  • the second polymer is optionally at a concentration below its overlap concentration.
  • the syneresis is caused by a superabsorbent polymer or is triggered by a second fluid that contacts the proppant carrier fluid downhole.
  • Another embodiment of the method of inducing proppant aggregation in a hydraulic fracture includes the steps of (1 ) formulating a proppant carrier fluid containing (i) at least one anionic polyelectrolyte or the precursor to at least one anionic polyelectrolyte, and (ii) at least one cationic polyelectrolyte or the precursor to at least one cationic polyelectrolyte; (2) injecting a slurry of the fluid and proppant; and (3) triggering formation of a polyelectrolyte complex.
  • the fluid may optionally contain fibers, and at least a portion of the proppant may be resin coated.
  • the formation of the polyelectrolyte complex is induced by a pH change; the formation of the polyelectrolyte complex is induced by conversion of at least one polyelectrolyte precursor to a polyelectrolyte; the formation of the polyelectrolyte complex is induced by formation of a cationic polyelectrolyte downhole; the cationic polyelectrolyte is formed downhole by a Mannich reaction or a Hofmann degradation of a polyacrylamide; the formation of the polyelectrolyte complex is induced by formation of an anionic polyelectrolyte downhole; the anionic polyelectrolyte is formed downhole by hydrolysis; at least one polyelectrolyte or polyelectrolyte precursor is initially present in the fluid in the internal phase of an emulsion; at least one polyelectrolyte or polyelectrolyte precursor is initially present in solid form; the formation of the polyelectroly
  • Yet another embodiment is a method of inducing proppant aggregation in a hydraulic fracture including the steps of (1 ) formulating a proppant carrier fluid containing a polymer below its lower critical solution temperature; and (2) injecting a slurry of the fluid and proppant into a subterranean formation that is above the lower polymer critical solution temperature.
  • the fluid may optionally contain fibers, and at least a portion of the proppant may be resin coated.
  • Figure 1 shows the dependency of syneresis vs. time for borate crosslinked guar gel samples having different concentrations of Ca(OH)2 at room temperature.
  • Figure 2 shows the syneresis of borate crosslinked guar gels in samples having different concentrations of Mg(OH) 2 at room temperature.
  • Figure 3 shows the syneresis of the borate crosslinked gel samples having varying concentrations of AICI 3 *6H 2 0.
  • the polymer gel phase transitions and polymer gel chemical transformations of the invention may be used in fracturing, gravel packing, and combined fracturing and gravel packing in a single operation.
  • the invention will be described in terms of treatment of vertical wells, but is equally applicable to wells of any orientation.
  • the invention will be described for hydrocarbon production wells, but it is to be understood that the invention may be used for wells for production of other fluids, such as water or carbon dioxide, or, for example, for injection or storage wells.
  • concentration or amount range is described as being useful, or suitable, or the like, it is intended that any and every concentration or amount within the range, including the end points, is to be considered as having been stated.
  • each numerical value should be read once as modified by the term “about” (unless already expressly so modified) and then read again as not to be so modified unless otherwise stated in context.
  • a range of from 1 to 10 is to be read as indicating each and every possible number along the continuum between about 1 and about 10.
  • the inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that the inventors have possession of the entire range and all points within the range.
  • HPP Heterogeneous proppant placement
  • the present invention encompasses a family of HPP methods in which proppant clusters, i.e. agglomerates or aggregates, are generated in situ in the fracture, and cluster formation timing and location are controlled by chemical means through polymer gel phase transitions or chemical transformations.
  • a polymer gel used as the viscosifier of a fracturing fluid is deliberately subjected to syneresis. This process is usually considered highly undesirable, as it drastically affects rheological properties of the fracturing fluid, and special efforts are often undertaken to avoid or diminish it.
  • syneresis with expulsion of water from the gel can lead to proppant particle aggregation.
  • the resulting polymer clots entrap and retain proppant inside them; the distance between particulates in the clots is significantly smaller than in the original homogeneous slurry.
  • the proppant aggregates (clusters) keeping the fracture from closure provide channels in between them and, thus, significantly enhanced fracture conductivity.
  • the polymer clots are formed due to interactions between two different polymers, triggered chemically.
  • An example is the formation of complexes between two oppositely charged polyelectrolytes.
  • the complex formation is accompanied by aggregation of proppant particulates and consequently HPP.
  • the proppant aggregation into clusters takes place due to a phase transition in a polymer solution.
  • a polymer solution with a low critical solution temperature (LCST) undergoes phase separation at bottomhole temperature and the resulting polymer precipitate consolidates proppant particles.
  • the proppant aggregates formed by the method of the invention can further be reinforced by resin curing, with fibers, or by other means known in the art.
  • the present invention discloses a method of heterogeneous proppant cluster formation by utilizing gel phase transitions and chemical transformations that lead to proppant aggregation.
  • Formation of heterogeneous proppant structures by the method of the invention may be controlled by syneresis of the fracturing gel.
  • Syneresis is defined herein as a process of water expulsion from a gel. Syneresis leads to a phase separation in the gel and to formation of a water phase caused by the collapse of the gel. When the gel contains proppant particles, the syneresis leads to proppant aggregation, which generally depends upon the degree of gel shrinkage.
  • the syneresis can be controlled by various means.
  • borate-crosslinked polymer gels and multivalent cations are used as well.
  • calcium hydroxide for example, calcium chloride, borate, and polymer are mixed at the surface.
  • Syneresis occurs after sufficient multivalent cation hydroxide is present. Generating the multivalent cation hydroxide in situ is preferred. The more calcium ion present, the greater and faster the syneresis.
  • multivalent cations may be used, for example Zn, Al, Mg, Fe, Cu, Cr, Co, Ti, Zr, and/or Ni.
  • the level of syneresis depends not only on the multivalent ion concentration but also on the borate crosslinking density. It should be noted that an inexpensive and/or unmodified guar may be used because the critical function may not be to provide viscosity and because impurities are not a problem if they end up in the agglomerated proppant. Yet one more method of causing and controlling syneresis is to use gel overcrosslinking.
  • controlled syneresis is promoted by the use of at least one crosslinker and/or at least one crosslinking delaying mechanism. Having more than one crosslinker and/or delaying mechanism allows initial pumping of a slurry having a conventional viscosity with the required degree of crosslinking, ensuring good proppant transport deep into a fracture.
  • the gel overcrosslinking takes place in the fracture and is induced by either a crosslinking system different from the system active during initial pumping or by additional delaying mechanism, or by both.
  • Crosslink delay agents which are known to those skilled in the art; examples include polyols, encapsulated crosslinkers, slowly dissolvable crosslinkers, and pH controlled and/or temperature-activated crosslinkers.
  • Slowly dissolvable crosslinkers can be used in a pure form or can be deposited/impregnated onto/into proppant particles.
  • Various crosslinking systems can be used according to the present invention, based on boron, any metal-based crosslinker systems known from the art (such as zirconium, chromium, iron, boron, aluminum, and titanium), and also based on organic compounds (such as aldehydes, dialdehydes, phenolic-aldehyde compositions, multifunctional amines and imines).
  • a slow crosslinker concentration increase in the gel leads to controlled gel overcrosslinking and syneresis.
  • the size of the resulting gel aggregates (clots) is controlled by shear history, gel composition and environment conditions.
  • Another method of syneresis control is the use of selective crosslinking.
  • a mixture of crosslinkable and non-crosslinkable polymers in which the non-crosslinkable polymer is a viscosifier, and in which crosslinkable polymer is present at a concentration below its overlap concentration, when the crosslinkable polymer crosslinks it forms what are commonly known as "microgels" (i.e. gel pieces which cannot overlap to fill space). These would form inside a viscous matrix of the non-crosslinkable polymer.
  • a mixture of two polymers and two crosslinkers may be used, in which each crosslinker crosslinks only one of the polymers.
  • One polymer/crosslinker combination viscosifies the fluid and the other polymer/crosslinker combination forms a microgel.
  • polymer mixtures Such a mixture may include similar-type polymers (for example different polysaccharides such as non-derivatized guar and carboxymethyl hydroxyethyl guar) or different-type polymers (for example polysaccharides and polyacrylamides).
  • the crosslinking systems may be, as examples, any of those mentioned above. Differing affinities to the crosslinker of different polymers lead to formation of gel volumes having different viscosities. The size and distribution of the volumes can be controlled by solution composition, mixing efficiency, and polymer properties.
  • SAPs superabsorbent polymers
  • the molecular weight and chemical properties of SAPs can be adjusted in such a way as to cause osmotic pressure to move water from the gel phase into the SAP phase. Loss of water by the gel leads to proppant particle aggregation.
  • Superabsorbent polymers may be added to a slurry in a dry state or in partially swollen state. The degree of swelling and the choice of the solvent used with the SAP can be used for control of competitive swelling of the gel and the SAP.
  • the absorbance of water by a superabsorbent can be triggered by pH, solution/gel ionic strength, temperature and by other factors.
  • SAP molecules can be either crosslinked or not.
  • Yet another method of controlling syneresis is the addition of fibers, for example polylactic acid fibers, to any of the systems mentioned above. Fibers do not affect the degree of syneresis but they do control the volume occupied by the shrunken gel. The more fibers used, the greater the final volume of the gel phase at the same degree of syneresis. In addition, the presence of fibers greatly changes the mechanical properties of the gel phase.
  • Carboxymethylated guars and celluloses are the most common such polymers used in drilling fluids and fracturing gels. These derivatized polysaccharides have polar carboxylic groups, making the polymers more water soluble, chemically resistant and crosslinkable with metals.
  • polyacrylic acid PA
  • PAM polyacrylamide
  • the PAMs contain anionic groups due either to intrinsic hydrolysis of acrylamide to acrylic acid, or due to deliberately incorporated sulfonic groups (e.g. acrylamido-2-methyl-1 -propane sulfonic acid, (AMPS).
  • AMPS acrylamido-2-methyl-1 -propane sulfonic acid
  • Polycations are used less often in oilfield technologies, as they are usually more expensive than their anionic counterparts. Examples of the most common polycations include different polyacrylamide copolymers with diallyldimethylammonium chloride (DADMAC), acryloyloxyethyltrimethylammonium chloride (AETAC) and other quaternary ammonium monomers, polyvinyl pyrrolidone (PVP), polyethyleneimine (PEI) and natural polymers, such as chitosan, gelatin (and other polypeptides), and poly-L-lysine.
  • DMAC diallyldimethylammonium chloride
  • AETAC acryloyloxyethyltrimethylammonium chloride
  • PVP polyvinyl pyrrolidone
  • PEI polyethyleneimine
  • natural polymers such as chitosan, gelatin (and other polypeptides)
  • PEC polyelectrolyte complex
  • PEC structures are available.
  • One is based on the formation of nearly stoichiometric complexes between polyelectrolytes of similar molecular weights; this is usually called a "ladder"-type complex, in which oppositely charged polymeric chains are aligned and linked ionically (as shown in route A, Fig. 4).
  • Water-soluble, ordered, non-stoichiometric complexes with the ladder-type structure are also known.
  • the polymer chains coil, forming a structure with statistical charge compensation (as shown in route B, Fig. 4).
  • Such complexes often have highly non-stoichiometric ratios of polyelectrolytes and are usually characterized by very low solubility. Utilization of these complexes is one of the embodiments of the present invention.
  • PEC clots represent highly crosslinked 3D networks of polymer chains, which may, additionally, as in the case of flocculants, have an affinity to the surfaces of entrapped particles due to electrostatic, van der Waals, hydrogen bonding and other forces.
  • PECs can be controlled in a variety of ways. pH delaying agents, known to those skilled in art, can be used to adjust the pH of a fracturing fluid and initiate PEC formation in a fracture.
  • the fracturing slurry in addition to proppant and other additives, is made from two polyacrylamide copolymers, the first of which is made with acrylic acid as one monomer and the second of which is made with DADMAC as one monomer.
  • Another method of controlling PEC formation is in situ synthesis of one polyelectrolyte downhole.
  • the Mannich aminomethylation or Hofmann degradation reactions of polyacrylamide polymer are used to produce polycationic species from initially neutral PAM. Both reactions proceed in aqueous solutions at temperatures above about 50 °C.
  • a PAM is treated with formaldehyde and an amine which results in formation of Mannich base groups (-NH-CH 2 -NR 2 ), which are positively charged even in solutions with relatively high pH values; the product is a polycation.
  • Secondary amines for example diethyl and dipropylamine are preferred, but ammonia and primary amines may also be used.
  • Formaldehyde can be obtained downhole from a precursor (for example urotropin (hexamethylenetetramine)), so no toxic substances are needed at a wellsite.
  • a precursor for example urotropin (hexamethylenetetramine)
  • Another method of generating a polyelectrolyte downhole is the Hofmann degradation reaction, in which a PAM is treated with hypohalogenites in alkaline solution, which leads to polyvinylamine, a cationic polyelectrolyte. Details of chemical transformations of PAMs under downhole conditions can be found in co-filed Patent Application "Subterranean Reservoir Treatment Method" invented by Makarychev-Mikhailov, and Khlestkin.
  • Yet another method of controlling (delaying) PEC formation is the utilization of any type of emulsion (oil-in-water, water-in-oil, water-in-water) to transport at least one polyelectrolyte downhole.
  • a fracturing slurry in addition to proppant and other additives, contains emulsion droplets, stable at ambient conditions, which confine a polyelectrolyte, which therefore is non-reactive towards its oppositely charged counterpart, also present in the slurry.
  • the emulsion breaks either under downhole conditions (at elevated temperature) or by means of a delayed emulsion breaker, releasing the polyelectrolyte, which immediately participates in a PEC formation reaction.
  • Yet another method of utilizing PEC's is to add one of the polymers or polymer precursors in solid form.
  • Any other methods of controlled (delayed) PEC formation may be used, for example based on temporary protection of the charged groups of at least one of the polyelectrolytes by means of chemical protection groups or surfactants (by using polyelectrolyte-surfactant complexes).
  • pH triggering that may be used to initiate PEC formation include:
  • Triggers other than PEC polymer complexes will lead to similar results.
  • other forces may be used as a driving force for polymer complex formation.
  • complexes based on hydrogen bonding provide a function similar to that of PECs described above.
  • any complex may be used which involves at least one polyelectrolyte.
  • Such a polyelectrolyte can be complexed with a variety of compounds, such as non- ionic polymers, surfactants, and inorganic species (for example, metal ions).
  • Stimulus-responsive polymers are a wide class of modern functionalized materials. They are able to perceive small changes in external signals, such as pH, temperature, electric/magnetic/mechanical field, or light, and produce corresponding changes or transformation of the physical structure and chemical properties of a polymer solution or gel. Much attention has been paid to chemical design and investigation of thermally sensitive or thermo-responsive polymers. In particular, they exhibit sensitive responses in their structure, properties, and configuration to changes in temperature. Aqueous solutions of certain polymers undergo fast, reversible changes around their lower critical solution temperature (LCST). Below the LCST, the free polymer chains are soluble in water and exist in an extended conformation that is fully hydrated.
  • LCST critical solution temperature
  • Thermo-responsive polymers have a variety of applications, such as temperature or pH-sensitive materials for drug delivery applications, biosensors, thermally responsive coatings, catalysis, soluble polymeric ligands for heavy metal scavenging, size selective separation and as water-dispersible hydrophobic thickening agents in the oilfield industry.
  • LCST polymers have inverse temperature dependent solubilities.
  • Polymers bearing amide groups form the largest group of thermo-sensitive polymers. Among them, poly(N-isopropylacrylamide) (PNIPAM) and poly(N,N'-diethylacrylamide) (PDEAAM) are most well known. They have similar LCSTs of 32 - 33 °C.
  • Poly(ethylene oxide) (PEO) is one of the most- studied biocompatible polymers that exhibit LCST behavior.
  • the LCST transition of PEO aqueous solutions occurs at temperatures ranging from about 100 °C to about 150 °C, depending upon the molecular weight. This temperature range extends PEO applications for temperature-sensitive purposes.
  • the properties of a polymer solution, such as the phase transition temperature depend on the chemical composition and the molecular weight of the polymer and on environmental conditions such as fluid pH and ionic composition and concentration.
  • polymers having low critical solution temperatures includes, but is not limited to, ethylene/vinyl alcohol copolymers; ethylene oxide/propylene oxide copolymers; copolymers of N,N-dimethylacrylamide with methyl acrylate, ethyl acrylate, propyl acrylate, butyl acrylate, 2- ethoxyethyl acrylate, and/or 2-methoxyethyl acrylate; hydroxypropyl cellulose; N-isopropylacrylamide/acrylamide copolymers; copolymers of N- isopropylacrylamide with 1-deoxy-1-methacrylamido-D-glucitol; N- isopropylmethacrylamide; methylcellulose (having various concentrations of methyl substitution); methylcellulose/hydroxypropylcellulose copolymers; polyphosphazene polymers, including poly[bis(2,3-dimethoxypropanoxy) phosphazene], poly[bis(2-(2'-meth
  • Thermo-responsive polymer flocculants can be used for aggregation of proppant particulates in a fracture.
  • the schematic below shows a representation of the aggregation mechanism of proppants using polymers having LCST behavior, Fig. 5.
  • the mechanism of particle agglomeration includes adsorption of polymer onto the surface of particles at temperatures below the LCST. Under these conditions, polymers are soluble in water, so there is hydrogen bonding between the polymer and water molecules; the polymer chains have an extended random coil conformation. When the temperature is increased above the LCST the hydrogen bonding is weakened, resulting in phase separation of the polymer and water, whereupon the polymer chains collapse and precipitate, entrapping proppant particulates.
  • LCST precipitates are also a way to induce or trigger the aggregation/agglomeration of proppant.
  • the formation of LCST precipitates leaves a water-like matrix fluid, leak-off will be high, leaving only the clots and proppant in the fracture.
  • a useful system is obtained if the LCST precipitates are formed in a way such that the residual matrix is a high viscosity low leak-off fluid.
  • the treatment sequence is typically as follows: inject a pad; inject a proppant- laden slurry containing at least one polyelectrolyte already in charged form and at least one non-ionic polymer, which can be converted to a polyelectrolyte with a charge opposite to that of the first polymer by a trigger or a delay agent; allow proppant aggregation; and allow fracture closure.
  • concentration of the polyelectrolytes and polyelectrolyte precursors is in the range of from about 0.005 to about 5 weight percent. Suitable triggering mechanisms for PEC formation are listed above.
  • the slurry may further contain oilfield additives, known to those skilled in the art, such as viscosifiers, surfactants, clay stabilizers, bactericides, fibers, etc.
  • the sequence would be as follows: pump a pad stage for fracture initiation; pump proppant- laden fluid that undergoes syneresis at downhole conditions; allow agglomeration of proppant; and allow the fracture to close on the aggregates formed.
  • the fluid formulation additionally contains fibers for agglomerate stabilization and settling prevention.
  • a suitable sequence of steps is the following: pump a pad stage for fracture initiation; pump proppant- laden fluid that undergo phase transition at downhole conditions (for example upon heating to downhole temperatures); allow agglomeration of proppant; and allow the fracture to close on the aggregates formed.
  • agglomeration is induced by pumping a pad stage for fracture initiation followed by pumping the two fluids to the perforation region by different flow paths, for example by pumping one fluid down coiled tubing and pumping the other fluid down the annulus between the coiled tubing and the wellbore.
  • Agglomerated particles are transported to the fracture. After the treatment the fracture closes on the agglomerates.
  • the method of the invention can be used in fractures of any size and orientation. It is particularly suitable for fractures in horizontal wellbores and/or in soft formations.
  • the agglomeration and resulting heterogeneous proppant placement should occur during the pumping or during an optional shut in period; it should occur before flowback.
  • a linear gel slurry containing 3.6 g/l (30 Ib/mgal) of guar and 406 g/l (4 ppa) of sand 0.300 - 0.106 mm (50/140 US ) was prepared with deionized water.
  • the gel was then crosslinked with different crosslinker concentrations (see Table 1).
  • the crosslinker consisted of a H 3 B0 3 :NaOH:CaCl2 mixture in a weight ratio of 3.1 :1 :1.3 in which the solids content was 50 weight percent in water. Noticeable gel collapse was observed in the sample with the highest borate concentration in 3 hours, while no change was found in the gel sample with the lowest crosslinker concentration.
  • the volumes of water expelled from the gel sample were measured after 24 hours of storage at room temperature. It was found that after syneresis all the proppant particles remained in the gel phase, where the proppant concentration was increased up to 2 times.
  • Slickwater sample 1 was prepared from a water-in-oil emulsion of anionic polyacrylamide-AMPS copolymer useful as a friction reducer at a concentration of 0.1 weight percent (1 gpt) in deionized water; about 10 mg of methylene blue dye was added to the sample.
  • Slickwater sample 2 was- prepared from a water-in-oil emulsion of cationic polyacrylamide also useful as a friction reducer at the same concentration in deionized water; about 10 mg of methyl orange was added.
  • Gels with 0.014 mol/L of aluminum (3.6 g/L of guar, 3.6 g/L of H 3 BO 3 , 3.26 g/L of AICI 3 *6H 2 O, and 55.4 ml/L of 5 weight percent NaOH) were prepared in deionized water and various amounts of 6 - 8 mm polylactic acid fiber were added to the samples. Fiber concentrations ranged from 0 to 10.3 g/L. After syneresis, the volume of shrunken gel was a function of the fiber concentration; the more fibers added, the greater the volume of the gel up to about 3.6 g/L fiber. From 3.6 to 10.3 g/L of fiber there was little apparent change in gel syneresis.
  • the influence of borate crosslinking site density on a syneresis level was examined.
  • Two samples of crosslinked gel with added copper ions were prepared with different concentration of borate.
  • the first sample was made from 3.6 g/L of guar, 0.652 g/L of CuCI 2 *2H 2 O, 3.6 g/L of H3BO3 and 29.1 ml/L of 5 weight percent NaOH in deionized water.
  • the second sample was made from 3.6 g/L of guar, 0.652 g/L of CuCI 2 -2H 2 O, 0.5 g/L H3BO3 and 9.1 ml/L of 5 weight percent NaOH in deionized water.
  • the syneresis levels were 70 percent in the sample with high boric acid concentration and 9 percent in the sample with low boric acid content.
  • the mean sizes of the agglomerates which formed were estimated by measurement on photographs of the sample bottle laid alongside a graduated scale.
  • the mean size of the agglomerates obtained under dynamic conditions (intensive agitation) was about 0.9 cm. Analysis of the agglomerates showed that they consisted of sand and precipitated polymer.
  • PEC polyelectrolyte complex
  • PHPA partially hydrolyzed polyacrylamide
  • PEI polyethyleneimine
  • a suspension of 10 g 0.850 - 0.425 mm (20/40) mesh sand was mixed with 100 g of deionised water in a 250 ml_ beaker using a flat-two-blade impeller driven at 270 rpm by an overhead mechanical stirrer. With continuous mixing (270 rpm), 25 g of a 1 weight percent PHPA solution (dissolved in 2 weight percent KCI) was added. After a further 10 minutes of continuous mixing, 2.5 g of a 10 weight percent PEI solution (dissolved in deionized water) was added and mixing was continued for 15 minutes. At this point, the aqueous phase of the mixture contained 0.196 weight percent PHPA polymer, 0.196 eight percent PEI polymer and 0.39 weight percent KCI.
  • the pH of the aqueous phase was sufficiently alkaline that the PEI polymer was uncharged, which inhibited precipitation of the PEC. Then acid was added to induce protonation of the PEI polymer and precipitation of the PEC; again with continuous mixing (270 rpm), 2 g of 1 molar HCI was added to the mixture using a Pasteur pipette to introduce the acid solution at the base of the agitating mixture. After a few minutes of continuous mixing, a voluminous and sticky PEC precipitate was formed.
  • the influence of ionic strength on the level of syneresis was examined. Two samples of crosslinked gel were prepared with different concentration of potassium chloride. The first sample was made from 3.6 g/L of guar, 7 g/L of H3BO3 and 42 ml/L of 5 weight percent NaOH in deionized water. The second sample was made from 3.6 g/L of guar, 7 g/L H3BO3, 42 ml/L of 5 weight percent NaOH in deionized water, and 20 g/L of KCI. After 2 hours at room temperature, the syneresis levels were 94 percent for the sample with potassium chloride and 0 percent for the sample without the salt.

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Abstract

Cette invention concerne un procédé conçu pour induire le placement d'un agent de soutènement dans une fracture hydraulique en provoquant l'agrégation de l'agent de soutènement à travers une transition de phase gel ou une transformation chimique dans le fluide porteur de l'agent de soutènement. L'agrégation de l'agent de soutènement peut être induite selon les étapes consistant à : provoquer ou permettre la synérèse du gel polymère qui rend le fluide visqueux ; former un complexe polyélectrolyte à partir de polymères cationiques et anioniques compris dans le fluide ou créés dans celui-ci, et ; porter la température du fluide au-dessus de la température critique de dissolution d'un polymère dans le fluide. Le fluide porteur de l'agent de soutènement peut être préparé de telle façon que ces transformations aient lieu naturellement pendant ou après l'injection de l'agent de soutènement. De plus, les transformations peuvent être initiées ou retardées de manière chimique.
PCT/RU2010/000207 2010-04-27 2010-04-27 Placement d'agent de soutènement hétérogène Ceased WO2011136678A1 (fr)

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US13/642,557 US20130056213A1 (en) 2010-04-27 2010-04-27 Heterogeneous Proppant Placement
MX2012012330A MX2012012330A (es) 2010-04-27 2010-04-27 Colocación de apuntalantes heterogéneos.
CA2797294A CA2797294A1 (fr) 2010-04-27 2010-04-27 Placement d'agent de soutenement heterogene
RU2012150663/03A RU2544943C2 (ru) 2010-04-27 2010-04-27 Неоднородное размещение расклинивающего агента
PCT/RU2010/000207 WO2011136678A1 (fr) 2010-04-27 2010-04-27 Placement d'agent de soutènement hétérogène
US14/620,979 US20150152321A1 (en) 2010-04-27 2015-02-12 Heterogeneous proppant placement

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US14/620,979 Continuation-In-Part US20150152321A1 (en) 2010-04-27 2015-02-12 Heterogeneous proppant placement

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US10316244B2 (en) 2011-08-31 2019-06-11 Self-Suspending Proppant Llc Self-suspending proppants for hydraulic fracturing
US9297244B2 (en) 2011-08-31 2016-03-29 Self-Suspending Proppant Llc Self-suspending proppants for hydraulic fracturing comprising a coating of hydrogel-forming polymer
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US20210215026A1 (en) * 2013-07-23 2021-07-15 Schlumberger Technology Corporation Methods of treatment of a subterranean formation with polymeric structures formed in situ
US10344195B2 (en) 2013-08-26 2019-07-09 Halliburton Energy Services, Inc. Controlling flow in downhole operations
US20150144339A1 (en) * 2013-11-25 2015-05-28 Schlumberger Technology Corporation Controlled inhomogeneous proppant aggregate formation
US9932521B2 (en) 2014-03-05 2018-04-03 Self-Suspending Proppant, Llc Calcium ion tolerant self-suspending proppants
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US11732179B2 (en) 2018-04-03 2023-08-22 Schlumberger Technology Corporation Proppant-fiber schedule for far field diversion
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US11713415B2 (en) 2018-11-21 2023-08-01 Covia Solutions Inc. Salt-tolerant self-suspending proppants made without extrusion

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MX2012012330A (es) 2013-01-29
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CA2797294A1 (fr) 2011-11-03
US20130056213A1 (en) 2013-03-07

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