WO2014124363A2 - Method of fracturing subterranean formations with crosslinked fluid - Google Patents
Method of fracturing subterranean formations with crosslinked fluid Download PDFInfo
- Publication number
- WO2014124363A2 WO2014124363A2 PCT/US2014/015565 US2014015565W WO2014124363A2 WO 2014124363 A2 WO2014124363 A2 WO 2014124363A2 US 2014015565 W US2014015565 W US 2014015565W WO 2014124363 A2 WO2014124363 A2 WO 2014124363A2
- Authority
- WO
- WIPO (PCT)
- Prior art keywords
- fracturing fluid
- fluid
- entrance site
- apparent viscosity
- less
- Prior art date
Links
Classifications
-
- 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
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
Definitions
- the invention relates to a method of fracturing a subterranean formation with an aqueous fluid which contains a hydratable polymer and a crosslinking agent wherein the apparent viscosity of the fluid decreases distally from the entrance site of the reservoir.
- Hydraulic fracturing often requires the use of well treating materials capable of enhancing the production of fluids and natural gas from low permeability formations.
- a fracturing treatment fluid containing a solid proppant is injected into the formation at a pressure sufficiently high enough to cause the formation or enlargement of fractures in the reservoir.
- the fractures radiate outwardly from the wellbore, typically from a few meters to hundreds of meters, and extend the surface area from which oil or gas drains into the well.
- the proppant is deposited in the fracture, where it remains after the treatment is completed. After deposition, the proppant serves to prevent closure of the fracture and to form a conductive channel extending from the wellbore into the formation being treated. As such, the proppant enhances the ability of fluids or natural gas to migrate from the formation to the wellbore through the fracture.
- the viscosity of most fracturing fluids may be attributable to the presence of a viscosifying agent, such as a viscoelastic surfactant or a viscosifying polymer, in the fluid.
- a viscosifying agent such as a viscoelastic surfactant or a viscosifying polymer
- Conventional viscosifying polymers include such water-soluble polysaccharides as galactomannans and cellulose derivatives.
- a crosslinking agent such as one which contains borate (or generates borate), titanate, or zirconium ions, in the fracturing fluid can further increase the viscosity.
- the increased viscosity of the gelled fracturing fluid affects both fracture length and width, and serves to place the proppant within the produced fracture.
- low viscosity fluids such as water, salt brine and slickwater
- a viscoelastic surfactant or viscosifying polymer have been used in the stimulation of low permeability formations.
- Such formations are also known as tight formations (including tight gas shale reservoirs exhibiting complex natural fracture networks).
- tight formations including tight gas shale reservoirs exhibiting complex natural fracture networks.
- Fractures propagated with low viscosity fluids exhibit smaller fracture widths than experienced with relatively higher viscosity fluids, resulting in development of greater created fracture area from which the hydrocarbons can flow into the high conductive fracture pathways.
- Slickwater fluids are basically fresh water or brine having sufficient friction reducing agent to minimize tubular friction pressures. Generally, such fluids have viscosities only slightly higher than unadulterated fresh water or brine; typically, the friction reduction agents present in slickwater do not increase the viscosity of the fracturing fluid by any more than 1 to 2 cP. Such fluids are much cheaper than conventional fracturing fluids which contain a viscosifying agent. In addition, their characteristic low viscosity facilitates reduced fracture height growth in the reservoir during stimulation. Further, such fluids introduce less damage into the formation in light of the absence of a viscosifying polymer and/or viscoelastic surfactant in the fluid.
- Such settling can occur as a result of insufficient slurry flow velocity and/or insufficient viscosity to suspend the proppant. Excessive proppant settling within a horizontal wellbore can necessitate cessation of fracturing treatments prior to placement of the desired volumes.
- high pumping rates are typically employed to effectively suspend the proppant for transport within the horizontal wellbore section. However, high pumping rates can result in higher than desirable treating pressures and excessive fracture height growth.
- a method of fracturing having particular applicability in tight gas reservoirs consists of mixing water and a viscosifying polymer, crosslinking agent and proppant and introducing the viscous fluid into the wellhead.
- the viscosity of the fracturing fluid when pumped into the wellhead may be between from about 10 to about 120 cP at a temperature range between from about 80° F to about 125° F. Increased viscosity at the surface protects the surface equipment when pumping the suspended proppant into the wellhead.
- the viscous nature of the fracturing fluid enables the fluid to transport the proppant to the perforating sites in the wellbore while minimizing settling.
- the loading of the hydratable polymer in the fracturing fluid is from about 6 to about 18 pptg, preferably from about 6 to about 12 pptg.
- the low loading of the viscosifying polymer in the fracturing fluid causes the viscosity of the fluid to rapidly decrease upon entering the entrance site of perforation.
- the viscosifying polymer is preferably a hydratable polymer including galactomannan gums, guars, derivatized guars, cellulose and cellulose derivatives, starch, starch derivatives, xanthan, derivatized xanthan and mixtures thereof.
- Particularly preferred viscosifying polymers are derivatized and underivatized guars having an intrinsic viscosity greater than about 14 dL/g, more typically greater than 16dL/g.
- the method described has particular applicability in low permeability reservoirs, such as those having permeabilities between from about 10 nanodarcies to about 1.0 mD, including shale and limestone.
- FIG. 1 is a schematic representation of the invention illustrating the viscosity profile of a fracturing fluid from the time the fluid is blended until the fluid travels distally 1 ,000 feet from the reservoir perforation site.
- FIGs. 2 through 6 are viscosity and temperature profiles over time of aqueous fracturing fluids defined herein.
- the fracturing method uses a fracturing fluid which is prepared by mixing an aqueous fluid, a hydratable polymer, a crosslinking agent and proppant (and buffering agent, if needed).
- the mixing may occur in a blender. Blending may occur on-the-fly. Alternatively, one or more of the aqueous fluid, hydratable polymer, crosslinking agent and/or proppant may be mixed downstream of the blender. Further, it is possible that the mixing of the components may occur downhole. [00021] In an embodiment, sufficient viscosity of the fluid is developed as the fluid is pumped into the wellhead such that proppant does may be transported to the wellhead and not settle from the fluid. As such, proppant settling in the manifold lines and the housing of the pump is minimized (to the extent that any settling occurs). Thus, unlike slickwater fluids, the fracturing fluids described herein minimize pump failures or damage to the pistons and/or manifolds of the pump.
- the apparent viscosity of the fracturing fluid 100 feet from the reservoir perforation sites (or entrance site) may be less than 10 percent of the apparent viscosity of the fracturing fluid at the entrance site of the reservoir.
- the apparent viscosity of the fracturing fluid 100 feet from the entrance site is less than 5 percent of the viscosity of the fracturing fluid at the entrance site.
- the apparent viscosity of the fluid 200 feet from the entrance site is less than 1 percent of the viscosity of the fracturing fluid at the entrance site.
- the apparent viscosity of the fracturing fluid 15 minutes after introduction into the entrance site may be less than 15% of the apparent viscosity of the fracturing fluid at the reservoir entrance site. More typically, the apparent viscosity of the fracturing fluid 15 minutes after introduction into the entrance site is less than 10% of the apparent viscosity of the fracturing fluid at the entrance site. Alternatively, the apparent viscosity of the fracturing fluid 30 minutes after introduction into the entrance site is less than 5% of the apparent viscosity of the fracturing fluid at the entrance site.
- the apparent viscosity of the fracturing fluid may be less than 10 cP within 15 minutes after being introduced through the entrance site of the reservoir. More typically, the apparent viscosity of the fracturing fluid is less than 5 cP within 15 minutes after being introduced through the entrance site. Alternatively, the apparent viscosity of the fracturing fluid is less than 3 cP within 30 minutes after being introduced through the entrance site.
- FIG. 1 illustrates a typical profile of the fracturing fluid defined herein as compared to fracturing fluids of the prior art. As illustrated, the fracturing fluid defined herein is labeled as "Fracturing Fluid".
- the Fracturing Fluid is compared to a conventional crosslinked gel which does not contain a delayed crosslinking agent and a conventional crosslinked gel which does contain a delayed crosslinking agent.
- the Fracturing Fluid is compared to slickwater. For each of the four fluids, it is assumed that an equivalent amount of proppant is in each fluid.
- the apparent viscosity of each of the fluids is then compared at the blender (where the crosslinking agent, hydratable polymer, proppant, and optionally a pH buffering agent, are mixed with the aqueous fluid), the high pressure pump where the fluid is pumped into the wellhead, at the wellhead itself and at the wellbore.
- the apparent viscosity is then shown at the perforation, 100 ft from the perforation, 200 ft from the perforation, 500 ft from the perforation and 1,000 ft from the perforation.
- the Fracturing Fluid is shown as having the approximate apparent viscosity as the delayed and non-delayed crosslinked fluids at the blender and high pressure pump. Further, the Fracturing Fluid is shown as having the approximate apparent viscosity as the delayed crosslinked fluid at the wellhead. At the wellbore and at the perforating site (entrance into the reservoir); the viscosity of the Fracturing Fluid approximates the viscosity of the conventional crosslinked fluid which does not contain a delayed crosslinking agent.
- the apparent viscosity of the Fracturing Fluid decreases.
- the apparent viscosity of the Fracturing Fluid approximates the apparent viscosity of slickwater.
- the viscosifying polymer of the fracturing fluid defined herein may be a thickening polymer such as a hydratable polymer like, for example, one or more polysaccharides capable of forming a crosslinked gel.
- a thickening polymer such as a hydratable polymer like, for example, one or more polysaccharides capable of forming a crosslinked gel.
- polysaccharides capable of forming a crosslinked gel.
- These include galactomannan gums, guars, derivatized guars, cellulose and derivatized celluloses, starch, starch derivatives, xanthan, derivatized xanthan and mixtures thereof.
- Specific examples include, but are not limited to, guar gum, guar gum derivative, locust bean gum, welan gum, karaya gum, xanthan gum, scleroglucan, diutan, cellulose and cellulose derivatives, etc.
- More typical polymers or gelling agents include guar gum, hydroxypropyl guar (HPG), carboxymethyl hydroxypropyl guar (CMHPG), hydroxyethyl cellulose (HEC), carboxymethyl hydroxyethyl cellulose (CMHEC), carboxymethyl cellulose (CMC), dialkyl carboxymethyl cellulose, etc.
- HPG hydroxypropyl guar
- CMHPG carboxymethyl hydroxypropyl guar
- HEC hydroxyethyl cellulose
- CMC carboxymethyl hydroxyethyl cellulose
- CMC carboxymethyl cellulose
- dialkyl carboxymethyl cellulose etc.
- polymers or gelling agents include guar gum, hydroxypropyl guar (HPG), carboxymethyl hydroxypropyl guar (CMHPG), hydroxyethyl cellulose (HEC), carboxymethyl hydroxyethyl cellulose (CMHEC), carboxymethyl cellulose (CMC), dialkyl carboxymethyl cellulose,
- guars set forth in U.S. Patent Publication No. 20050272612 published on December 8, 2005, herein incorporated by reference.
- Such derivatized and underivatized guars are characterized by an intrinsic viscosity greater than about 14 dL/g, more typically greater than 16dL/g. This viscosity is indicative of higher molecular weight than that normally seen with derivatized and underivatized guars.
- the guars are obtained by improvements in the processing conditions used to convert the guar split (seed endosperm) to a fine powder.
- the cause of the increased molecular weight is due to improved processing conditions used to convert the guar split to a fine powder.
- the guar split being about 0.3 cm in diameter, is partially hydrated and sheared through a roll mill to produce a flake.
- the flake being more fragile, can then be dried and pulverized by a high impact mill.
- a means of obtaining a higher molecular weight polymer occurs at those places of high mechanical shear in the process.
- the shear process is modified so that the ultimate amount of shear is the same, but the rate of shear is reduced to allow the polymer chains in the split to relax rather than rupture. Therefore by reducing the shearing rate, the degree of rupture is reduced and the polymer molecular weight is higher.
- the crosslinking agent used in the aqueous fracturing fluid defined herein may be any crosslinking agent suitable for crosslinking the hydratable polymer.
- suitable crosslinking agents include metal ions such as aluminum, antimony, zirconium and titanium-containing compounds, including organotitanates.
- suitable crosslinkers may also be found in U.S. Pat. No. 5,201,370; U.S. Pat. No. 5,514,309, U.S. Pat. No. 5,247,995, U.S. Pat. No. 5,562,160, and U.S. Patent No. 6, 1 10,875, incorporated herein by reference.
- the crosslinking agent is a source of borate ions such as a borate ion donating material.
- borate-based crosslinking agents include, but are not limited to, organo-borates, mono-borates, poly-borates, mineral borates, etc.
- a pH adjusting material preferably is added to the aqueous fluid after the addition of the polymer to the aqueous fluid.
- Typical materials for adjusting the pH are commonly used acids, acid buffers, and mixtures of acids and bases. Normally, a pH between from about 9.5 to about 1 1.5 is desired.
- a buffering agent that is effective to provide the pH for the fluid may be used.
- Suitable buffering materials include potassium carbonate or mixtures of potassium carbonate and potassium hydroxide.
- the aqueous fluid may be brine, fresh water or salt water.
- the aqueous fluid may be produced water, recycled water (such as recovered from a previous frac), industrial waste water or waste water associated with oil production.
- the proppant for use in the aqueous fracturing fluid may be any proppant suitable for hydraulic fracturing known in the art. Examples include, but are not limited to, silica, quartz sand grains, glass and ceramic beads, walnut shell fragments, aluminum pellets, nylon pellets, resin-coated sand, synthetic organic particles, glass microspheres, sintered bauxite, mixtures thereof and the like.
- the proppant may be an ULW proppant. Proppants of intermediate to high strength having an ASG in excess of 2.45 are typically preferred, however, over ULW proppants.
- the viscosity of the fracturing fluid described herein, when being pumped from the blender into the wellbore, is typically between from about 10 to about 120 cP at a temperature range between from about 80° F to about 120° F, though a viscosity between from about 10 to about 50 cP is more preferred.
- the loading of the hydratable polymer in the fracturing fluid is from about 6 to about 18 pptg, preferably from about 6 to about 12 pptg. In another preferred embodiment, the polymer loading in the fracturing fluid is from about 6 to about 10 pptg. Low loading means less formation damage. Since use of the fluid enables placement of proppant earlier in the fracturing job, the total volume of fluid required for a job is decreased (in comparison to a similar job using conventional fluids). As such, the fracturing fluid defined herein offers increased fluid efficiency over conventional fluids.
- a breaker in the fluid to assist in the degradation of the hydratable polymer once the fracturing fluid has entered into the fracture.
- Any suitable breakers are used, including, but not limited to, solid acid precursors, for example, polyglycolic acid (PGA) or polylactic acid (PLA) particles such as beads, plates, or fibers, other delayed acids, delayed oxidizers or delayed bases.
- PGA polyglycolic acid
- PLA polylactic acid
- enzymatic breakers known in the art may be used.
- the method described herein has particular applicability in the fracturing of tight gas formations, especially those having a permeability less than 1 millidarcy.
- the method has applicability in those formations having a permeability of less than 100 microdarcy, and even less than 1 microdarcies.
- the method even has applicability in those formations having a permeability of less than 1 microdarcy and even less than 500 nanodarcies
- the method described herein has particular applicability in the fracturing of any formation which may be hydraulically fractured with slickwater.
- the method described herein is applied to formations of shale and tight gas sands, as well as limestone.
- a fluid was formulated by mixing at room temperature in a blender underivatized guar having an intrinsic viscosity greater than 16 dL/g, commercially available from Baker Hughes Incorporated as GW-2, a borate crosslinker, commercially available from Baker Hughes Incorporated as XLW-10.
- the loading of the polymer in the fluid varied to be between 6 and 10 pptg (pounds per thousand gallons).
- the amount of crosslinker in the fluid was varied to be between 1.0 and 3.0 gptg (gallons per thousand gallons).
- the fluid was buffered to a pH of 9.0. About 30 ml of the fluid was then placed into a Fann 50 viscometer cup having a bob (BX5) and rotor (Rl) cup assembly.
- FIG. 2 shows the results wherein 10 pptg of the fluid with 1 and 2gptg XLW-10 had initial viscosities of 500 cP and 350 cP, respectively, declining after 5minutes to about 400 cP and 200 cP, respectively, and after 10 minutes, to about 250 cP and 150cP, respectively. After 45 minutes, these fluids had viscosities of between 80 and 90cP. Further, 8 pptg of the fluid having 1.5 and 2 gptg of XLW-10 crosslinker had initial viscosities of 220 and 250 cP, respectively.
- the 8 pptg fluids exhibited 35 to 60 cP. After 45 minutes, the fluids had viscosities of 30 and 35 cP.
- a 6 pptg fluid having 2-3 gptg XLW-10 had initial viscosities of 80cP, declining to between 10 and 30 cP after 10 minutes. After 45 minutes, the fluids had viscosities between 10 and 15cP.
- a fluid was formulated by adding GW-2 to water in a blender at room temperature and then adding to the fluid a borate crosslinker, commercially available from Baker Hughes Incorporated as XLW-32.
- a 10% caustic solution sodium hydroxide
- the loading of the polymer in the fluid was between from 0.5 gptg to 2.0 gptg.
- the amount of crosslinker in the fluid was varied to be between 1.25 gptg and 1.75 gptg.
- About 30 ml of a 10 pptg fluid was then placed into a Fann 50 viscometer cup having a bob (BX5) and rotor (Rl) cup assembly.
- FIG. 3 demonstrates the 10 pptg fluid was acceptable at low polymer loadings at 100° F and 120° F. particular, FIG.
- Example 3 A fluid was formulated by mixing at a temperature range of from 75° F to 150° F in a blender water, from 2.0 to 3.0 underivatized guar having an intrinsic viscosity— greater than 16 dL/g, commercially available from Baker Hughes Incorporated as GW-2LDF and 3 gpt of a self-buffering borate crosslinker, commercially available from TBC-Brinadd as PfP BXL 0.2. The pH of the fluid was buffered to 9.0. About 30 ml of the fluid was then placed into a Fann 50 viscometer cup having a bob (BX5) and rotor (Rl) cup assembly. The cup was then placed on a Fann 50 viscometer.
- BX5 bob
- Rl rotor
- FIG. 4 shows the viscosity profiles of fluids having 8, 10 and 12 pptg. As illustrated, the crosslinked fluid viscosities of each of the example formulations were reduced by 40% to 60% due to increasing the fluid temperature from 75°F to 150°F.
- a fluid was formulated by adding GW-2 to water in a blender at room temperature and then adding to the fluid a self-buffering borate crosslinker, commercially available from Baker Hughes Incorporated as XLW-10.
- the crosslinked fluid formed in approximately 5 seconds.
- the loading of the polymer in the fluid was between from 6 pptg to 10 gptg.
- the amount of crosslinker in the fluid was varied to be between 1.5 gptg and 3.0 gptg.
- About 30 ml of a 10 pptg fluid was then placed into a Fann 50 viscometer cup having a bob (BX5) and rotor (Rl) cup assembly. The cup was then placed on a Fann 50 viscometer.
- FIG. 5 shows the viscosity profiles of each of the fluids as the temperatures was increased from ambient to 120°F.
- a fluid was formulated by adding 10 pptg of GW-2 to water in a blender at room temperature and then adding 3 ppt of boric acid as a crosslinker, 2 gptg of 10% caustic to bring the pH to about 9.5, and 0.125 ppt to 0.5 ppt of ammonium persulfate breaker, available from Baker Hughes Incorporated as GBW-5.
- the crosslinked fluid began to form in approximately 5 seconds.
- About 30 ml of a 10 pptg fluid was then placed into a Fann 50 viscometer cup having a bob (BX5) and rotor (Rl) cup assembly. The cup was then placed on a Fann 50 viscometer.
- FIG. 6 shows the viscosity profiles of each of the fluids as the temperatures was increased from ambient to 150°F. Viscosities for the example fluids were approximately 40 cP after about 30 seconds, and peaked at greater than 60 cP between 2 minutes and 5 minutes.
- the temperature had increased to about 120°F, and the viscosities of each of the fluids declined to between 10 and 15 cP. After 20 minutes, the temperature was at the target of 150°F and the fluids viscosities were observed to be less than 10 cP for each of the fluid formulations including breaker.
Landscapes
- Engineering & Computer Science (AREA)
- Life Sciences & Earth Sciences (AREA)
- Chemical & Material Sciences (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- Geochemistry & Mineralogy (AREA)
- Physics & Mathematics (AREA)
- Materials Engineering (AREA)
- Organic Chemistry (AREA)
- Compositions Of Macromolecular Compounds (AREA)
- Processes Of Treating Macromolecular Substances (AREA)
Abstract
Description
Claims
Priority Applications (3)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
EP14706437.2A EP2954158A2 (en) | 2013-02-11 | 2014-02-10 | Method of fracturing subterranean formations with crosslinked fluid |
BR112015019169-0A BR112015019169B1 (en) | 2013-02-11 | 2014-02-10 | METHOD OF FRACTURING UNDERGROUND FORMATIONS WITH RETICULATED FLUID |
CA2899331A CA2899331A1 (en) | 2013-02-11 | 2014-02-10 | Method of fracturing subterranean formations with crosslinked fluid |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US13/764,638 US9194223B2 (en) | 2009-12-18 | 2013-02-11 | Method of fracturing subterranean formations with crosslinked fluid |
US13/764,638 | 2013-02-11 |
Publications (2)
Publication Number | Publication Date |
---|---|
WO2014124363A2 true WO2014124363A2 (en) | 2014-08-14 |
WO2014124363A3 WO2014124363A3 (en) | 2015-04-23 |
Family
ID=50159576
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
PCT/US2014/015565 WO2014124363A2 (en) | 2013-02-11 | 2014-02-10 | Method of fracturing subterranean formations with crosslinked fluid |
Country Status (4)
Country | Link |
---|---|
EP (1) | EP2954158A2 (en) |
BR (1) | BR112015019169B1 (en) |
CA (1) | CA2899331A1 (en) |
WO (1) | WO2014124363A2 (en) |
Families Citing this family (2)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
CN106321045B (en) * | 2016-08-23 | 2019-01-15 | 杰瑞能源服务有限公司 | A kind of fracturing integrated tool tubular column of horizontal well orientation abrasive perforating and construction method |
CN106761651B (en) * | 2016-12-09 | 2019-06-04 | 中国石油集团川庆钻探工程有限公司工程技术研究院 | A kind of fracturing process of coal bed gas well Low Damage high flow conductivity man-made fracture |
Citations (6)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US5201370A (en) | 1992-02-26 | 1993-04-13 | Bj Services Company | Enzyme breaker for galactomannan based fracturing fluid |
US5247995A (en) | 1992-02-26 | 1993-09-28 | Bj Services Company | Method of dissolving organic filter cake obtained from polysaccharide based fluids used in production operations and completions of oil and gas wells |
US5514309A (en) | 1991-01-25 | 1996-05-07 | Rapid Cool Corporation | Pulsed gas parison cooling method |
US5562160A (en) | 1994-08-08 | 1996-10-08 | B. J. Services Company | Fracturing fluid treatment design to optimize fluid rheology and proppant pack conductivity |
US6110875A (en) | 1997-03-07 | 2000-08-29 | Bj Services Company | Methods and materials for degrading xanthan |
US20050272612A1 (en) | 2004-06-04 | 2005-12-08 | Dawson Jeffrey C | Galactomannan based well treating fluids |
Family Cites Families (2)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US8486867B2 (en) * | 2009-10-15 | 2013-07-16 | Baker Hughes Incorporated | Method of fracturing using mannanohydrolase enzyme breaker |
US8371383B2 (en) * | 2009-12-18 | 2013-02-12 | Baker Hughes Incorporated | Method of fracturing subterranean formations with crosslinked fluid |
-
2014
- 2014-02-10 BR BR112015019169-0A patent/BR112015019169B1/en active IP Right Grant
- 2014-02-10 WO PCT/US2014/015565 patent/WO2014124363A2/en active Application Filing
- 2014-02-10 CA CA2899331A patent/CA2899331A1/en not_active Abandoned
- 2014-02-10 EP EP14706437.2A patent/EP2954158A2/en not_active Withdrawn
Patent Citations (6)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US5514309A (en) | 1991-01-25 | 1996-05-07 | Rapid Cool Corporation | Pulsed gas parison cooling method |
US5201370A (en) | 1992-02-26 | 1993-04-13 | Bj Services Company | Enzyme breaker for galactomannan based fracturing fluid |
US5247995A (en) | 1992-02-26 | 1993-09-28 | Bj Services Company | Method of dissolving organic filter cake obtained from polysaccharide based fluids used in production operations and completions of oil and gas wells |
US5562160A (en) | 1994-08-08 | 1996-10-08 | B. J. Services Company | Fracturing fluid treatment design to optimize fluid rheology and proppant pack conductivity |
US6110875A (en) | 1997-03-07 | 2000-08-29 | Bj Services Company | Methods and materials for degrading xanthan |
US20050272612A1 (en) | 2004-06-04 | 2005-12-08 | Dawson Jeffrey C | Galactomannan based well treating fluids |
Also Published As
Publication number | Publication date |
---|---|
EP2954158A2 (en) | 2015-12-16 |
CA2899331A1 (en) | 2014-08-14 |
BR112015019169A2 (en) | 2017-07-18 |
BR112015019169B1 (en) | 2021-08-31 |
WO2014124363A3 (en) | 2015-04-23 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
US9410415B2 (en) | Method of fracturing subterranean formations with crosslinked fluid | |
US8371383B2 (en) | Method of fracturing subterranean formations with crosslinked fluid | |
US9175208B2 (en) | Compositions and methods for breaking hydraulic fracturing fluids | |
Barati et al. | A review of fracturing fluid systems used for hydraulic fracturing of oil and gas wells | |
CA2817871C (en) | Methods to create high conductivity fractures that connect hydraulic fracture networks in a well | |
US9441150B2 (en) | Low damage seawater based frac pack fluid | |
CN105358651B (en) | Iron-containing breaker compounds and methods of their use | |
CA2861119C (en) | Method of delaying crosslinking in well treatment operation | |
CN105849225B (en) | Propellants for iron compound-containing breakers | |
US20120252707A1 (en) | Methods and compositions to delay viscosification of treatment fluids | |
EP2954158A2 (en) | Method of fracturing subterranean formations with crosslinked fluid | |
US9909056B2 (en) | Method of altering crosslink time of delayed borate crosslinkers | |
Zhao | Investigation of the Applications of Nanofibrillated Cellulose in the Oil Industry | |
WO2018128537A1 (en) | Crosslinker slurry compositions and applications |
Legal Events
Date | Code | Title | Description |
---|---|---|---|
121 | Ep: the epo has been informed by wipo that ep was designated in this application |
Ref document number: 14706437 Country of ref document: EP Kind code of ref document: A2 |
|
ENP | Entry into the national phase |
Ref document number: 2899331 Country of ref document: CA |
|
REG | Reference to national code |
Ref country code: BR Ref legal event code: B01A Ref document number: 112015019169 Country of ref document: BR |
|
REEP | Request for entry into the european phase |
Ref document number: 2014706437 Country of ref document: EP |
|
WWE | Wipo information: entry into national phase |
Ref document number: 2014706437 Country of ref document: EP |
|
121 | Ep: the epo has been informed by wipo that ep was designated in this application |
Ref document number: 14706437 Country of ref document: EP Kind code of ref document: A2 |
|
ENP | Entry into the national phase |
Ref document number: 112015019169 Country of ref document: BR Kind code of ref document: A2 Effective date: 20150811 |