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
• • 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
• • 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
  • E21B47/00—Survey of boreholes or wells

Definitions

• the present invention relates to the stimulation of the production of subterranean hydrocarbon formations or stimulation of fluid injection into subterranean formations in a hydraulic fracturing process. More particularly, the present invention relates to an improved process for hydraulic fracturing in which performance of additives, in particular, friction reducers, is enhanced.
• hydraulic fracturing in which a fracturing fluid is introduced into an oil or gas well via a conduit, such as tubing or casing, at a flow rate and a pressure to create, reopen and/or extend a fracture into the well, allowing access to the oil or gas within the formation.
• the fracturing fluid is typically a water based solution and may comprise components such as suspended proppants (e.g., sand, bauxite); biocides to inhibit growth of bacteria and other microorganisms; corrosion inhibitors and scale inhibitors which reduce rust formation and other deposits on the conduit; and friction reducers to promote laminar flow of the hydraulic fracturing fluid into the formation and reduce the pumping pressure necessary to achieve the desired fracturing fluid flow rate.
• suspended proppants e.g., sand, bauxite
• biocides to inhibit growth of bacteria and other microorganisms
• corrosion inhibitors and scale inhibitors which reduce rust formation and other deposits on the conduit
• friction reducers to promote laminar flow of the hydraulic fracturing fluid into the formation and reduce the pumping pressure necessary to achieve the desired fracturing fluid flow rate.
• Non-oxidizing biocides include glutaraldehydes and quaternary amine-glutaraldehyde combinations.
• friction reducing polymers can be sensitive to pH. It is known, for example, that performance of a hydrolyzed (anionic)
• polyacrylamide friction reducer is reduced at or below pH 4.5. At low pH, protonation of the polyacrylamide friction reducers can inhibit its ability to hydrate and unwind rapidly, thus, reducing its friction-reducing ability.
• flow back water contains contaminants such as hydrocarbons, minerals, and salts that are extracted from the formation during the fracturing process in addition to components of the fracturing fluid, including biocides, friction reducers, etc. that were introduced as part of the fracturing fluid.
• the water becomes "produced water", which is the naturally occurring water in the formation. Flow back and produced water cannot simply be disposed of in a local stream, river, or shallow aquifer, but must be treated to remove contaminants.
• the present invention provides a process for hydraulic fracturing in which a fracturing fluid comprising a friction-reducing polymer and an oxidizing biocide is introduced into a well.
• the process comprises providing a fracturing fluid by (a) combining water, proppant, an oxidizing biocide, and a friction reducer; (b) introducing the fracturing fluid into a well; and (c) controlling the pH of the fracturing fluid to a pH of at least about 4.5.
• Controlling pH surprisingly stabilizes performance of a friction reducer, when an oxidizing biocide is used.
• the process of this invention has a greater tolerance to contaminants from produced water.
• pH may be controlled by: (i) measuring the pH of (1 ) at least one of the water, oxidizing biocide, or friction reducer, prior to step (a) or (2) the fracturing fluid, prior to or after the fracturing fluid is introduced into a well in step (b); (ii) comparing the measured pH with a set point of a desired pH; (iii) calculating the difference between the desired pH and the measured pH ; and (iv) generating a signal which corresponds to the difference calculated in (iii) which provides a feedback response to a controller for adding a base to at least one of the water, oxidizing biocide or friction reducer or the fracturing fluid to control the pH of the fracturing fluid at a pH of at least about 4.5.
• any one or all of the steps (i) through (iv) may be performed manually.
• the pH of the desired component or fracturing fluid may be measured either manually or by an automated monitoring system. Comparing and calculating steps may be performed manually or electronically.
• the step of generating a signal may be an automated computer response to an in-line or on-line control system.
• individuals may monitor the pH and manually operate a feed pump to add base to the water, oxidizing biocide, or friction reducer, or the fracturing fluid.
• One operator may, for example, be positioned in a monitoring room observing pH, and may contact a second operator (i.e., generate and send a signal) with instructions (i.e., a feedback response) to add base, such as from a manual feed pump, to control pH.
• a second operator i.e., generate and send a signal
• instructions i.e., a feedback response
• Fig. 1 illustrates the providing of a fracturing fluid and the controlling of the pH thereof according to one embodiment of the present invention.
• the present invention is a process for hydraulic fracturing wherein a fracturing fluid is introduced (injected) into an oil or gas well at a flow rate and a pressure to create, reopen and/or extend a fracture into the formation around the well, allowing access to the oil or gas within a subterranean formation.
• the fracturing fluid comprises water, proppants, an oxidizing biocide and a friction reducer.
• the fracturing fluid may further comprise other components such as scale inhibitors and corrosion inhibitors.
• oxidizing biocide is meant herein a compound that has biocidal activity, meaning reduces the amount of bacteria and other microorganisms that may be present in the fracturing fluid as well as has the potential for oxidizing other components in the fracturing fluid.
• oxidizing biocides include bleach (sodium hypochlorite, NaOCI), peroxides, such as hydrogen peroxide, peracids, such as peracetic acid, persulfates, ozone and chlorine dioxide.
• Preferred biocides include bleach, peracetic acid and chlorine dioxide.
• the oxidizing biocide is generally added in an amount to provide a free residual in the fracturing fluid.
• the residual may be about 1 -5 ppm of the oxidizing biocide.
• the biocide is chlorine dioxide, for example, a dose of as great as 150 ppm CIO2 may be required to provide a target of 1 -5 ppm residual to achieve an appropriate level of disinfection.
• Chlorine dioxide is a preferred oxidizing biocide. Chlorine dioxide is a gas and can be generated onsite at the oil or gas well location. Various methods are known for generating chlorine dioxide, including chemical and electrochemical processes as disclosed for example in Ullmann's
• One particular method of generating chlorine dioxide involves reaction of an alkali metal chlorite, such as sodium chlorite with an acid, such as hydrochloric acid or sulfuric acid as illustrated below.
• the generated product may have an undesirably low pH which can lower the pH of any fluid it is injected into.
• pH of the fracturing fluid as set forth herein, the issue of overfeeding acid from any source is addressed without adversely affecting performance of the friction reducer.
• Friction reducer is added to a fracturing fluid to promote laminar flow of the fracturing fluid, which is important to achieve desired fracturing at lower pressures while maintaining high flow rates into the formation. Performance of the friction reducer is critical to achieve desired flow rates at desired pressure. Poor performance of a friction reducer causes increased pressure or reduced flow rate, either of which will negatively impact the fracturing process by increasing energy costs for higher pressure or increasing time and/or efficiency to achieve the desired fracturing at a lower pressure.
• Friction reducers include organic polymers such as acrylic acid and acrylamide polymers and copolymers. Friction reducers may be anionic, cationic, and nonionic. Anionic friction reducers are lower cost and are the most widely used. Anionic friction reducers are typically modified
• Friction reducers may be an acrylic-acid-AMPS-polyacrylamide terpolymer, a brine dispersion AMPS-polyacrylamide copolymer, or a non- ionic polyacrylamide polymer. Friction reducers may be supplied as aqueous dispersions or mixed aqueous/petroleum distillate dispersions of a polymer concentrate. A preferred friction reducer is a polyacrylamide.
• Friction reducers are typically dosed in an amount of 50 - 1000 ppm
• An advantage of the present invention is that when pH is suitably controlled, at least a portion of the water used for fracturing, which can average about 3000 gallons (1 1 ,000 liters) per minute, or more, can be flow back and produced water.
• Flow back water that is recovered from the fracturing operation and produced water may comprise metal salts including ferrous and ferric metal salts, hydrocarbons, and residual biocide, friction reducer and other additives.
• metal salts including ferrous and ferric metal salts, hydrocarbons, and residual biocide, friction reducer and other additives.
• the presence of metal salts in the produced water interferes with performance of the friction reducer.
• produced water is characterized as having a high iron content.
• Proppant which keeps an induced hydraulic fracture open during or following a fracturing treatment, is most commonly sand but can also be any other such particulate material with adequate mechanical properties to withstand closure stresses including, for example, ceramic, glass, and bauxite.
• the fracturing fluid may comprise other components, including, for example, polymers, breaking agents, scale inhibitors, corrosion inhibitors, etc. These other components may be added to the biocide or to the water, or still other options for adding are available.
• the process of this invention comprises providing a fracturing fluid by combining water, proppant, an oxidizing biocide, and a friction reducer. This combining step may be in a single step or multiple steps.
• the water may be treated with the biocide and with other components such as a scale inhibitor and a corrosion inhibitor prior to combining the treated mixture with proppant and the friction reducer.
• the biocide treated water may be stored, for example for periods of time of about 30 minutes or less prior to combining with friction reducer.
• the water used may consist of all fresh water, usually from a local stream, pond, or potable water supply, or a mixture of fresh water and produced water.
• the fresh and produced water may be supplied to treatment manifold in a single stream or in multiple streams.
• Frrac tanks are often used as a source of water to supply a constant flow of water to the fracturing process. Water may be supplied to a
• blending/mixing device such as a ribbon mixer into which friction reducer, proppant and biocide or biocide mixture are added to produce the fracturing fluid.
• the fracturing fluid is introduced - or injected - into the well at a pressure of 2000-15,000 psi (13.8-103 MPa), typically 8000-10,000 psi (55-69 MPa).
• the flow rate is typically several thousand gallons per minute, such as 4000 gallons per minute (15,000 liters per minute).
• pH of the fracturing fluid is controlled at a pH of at least about 4.5.
• pH is controlled at a pH of at least about 5.5.
• pH is controlled at pH less than about 7, preferably less than about 6.5.
• a measurement of pH is needed. This measurement may be taken of one or more of the components of the fracturing fluid, wherein the components of the fracturing fluid may be selected from the water, the biocide, or the friction reducer. Alternatively, the pH of the fracturing fluid may be measured. The pH of the fracturing fluid may be measured prior to or after introducing into the well. The measured pH is compared with a set point of a desired pH for the component or of the fracturing fluid. The difference between the desired pH and the measured pH is calculated.
• a signal is generated which corresponds to the calculated difference, which provides a feedback response to a controller for adding a base to the at least one of the water, biocide or friction reducer or the fracturing fluid to control the pH of the fracturing fluid at a pH of at least about 4.5, preferably at least about 5.5.
• the base can be an alkali metal salt or alkaline earth metal salt of hydroxide, oxide, bicarbonate, carbonate, or combinations of two or more thereof, as well as the base produced by ammonia dissolved into water (ammonium hydroxide base).
• the base is water soluble, more preferably the base is an aqueous solution.
• the base will not cause precipitation of metal ions present in the produced water.
• the produced water for example, comprises barium, calcium and magnesium
• the base is preferably an alkali metal hydroxide, more preferably an aqueous solution of ammonium hydroxide or an alkali metal hydroxide.
• preferred alkali metal hydroxides bases are hydroxides of lithium, sodium and potassium, more preferred as aqueous solutions. Most preferred are aqueous solutions of ammonium hydroxide, or, sodium hydroxide, potassium hydroxide or a combination thereof.
• Fig. 1 illustrates the providing of a fracturing fluid and the controlling of the pH of the fracturing fluid according to one embodiment of the present process for hydraulic fracturing.
• Certain detailed features of the present process such as pumps, flow controllers, feed tanks, and other ancillary process equipment are not shown for the sake of simplicity and in order to demonstrate the main features of the process.
• Such ancillary features can be easily designed and used by one skilled in the art without any difficulty or undue experimentation.
• water from feed line 12 is treated by contact with chlorine dioxide biocide from feed line 15 and delivered to reservoir 21
• frac tank commonly referred to as a "frac tank".
• the pH of the treated water is measured 18 and a suitable amount of base is injected via line 16 to control the pH to a value of at least greater than 4.5.
• the chlorine dioxide-treated water with pH greater than 4.5 is drawn from the frac tank through line 32 and contacted with friction reducer from line 34 and proppant from line 35 in mixing vessel 37 to form the finished fracturing fluid which is then introduced via line 38 to the well.
• KemFlowTM A4251 is an anionic, hydrolyzed polyacrylamide polymer
• KemFlowTM A4358 is an anionic polyacrylamide acrylic acid copolymer
• KemFlowTM C4107 is a cationic polyacrylamide polymer.
• Example 1 This example provides the results of friction loop tests which
• Friction loop tests were carried out at Stim-Lab, Inc. located in Duncan, OK, using a standard apparatus known to those skilled in the art. For each test, approximately 9 gallons of test fluid was circulated at 10 gallons/minute (approx. Reynolds number of 75,000). The friction reduction was calculated from the pressure drop across a precise length of the test loop.
• the water used to prepare the test fluids was a blend of 40% produced water from the Marcellus shale formation and 60% surface water collected from a location in Pennsylvania.
• the unadjusted pH of the water was 5.8.
• the water was acidified with sulfuric acid. In some cases the acidified water was also treated to contain about 10 mg/L residual CIO 2 .
• the test temperature was about 24 °C (75 °F).
• Samples 2B and 2C were prepared from this water and 99.5% iron(ll) heptahydrate so that the added Fe 2+ content was 25 and 50 mg/L, respectively.
• Sample 2A was a control sample and contained no added iron.
• 30 mg/L CIO2 was applied, after which the pH and residual CIO 2 was measured about 30 minutes later. Results, which were gathered at ambient laboratory temperatures of about 20-22 C, are summarized in the following table.
• Control sample 2A without Fe , shows no substantial change in pH with addition of CIO2 and substantially no consumption of CIO2 (the applied and residual amount is substantially the same).
• CIO 2 addition to Fe 2+ -containing samples 2B and 2C causes substantial decrease in pH to levels below 4.5. Consistent with the oxidation of the iron, the residual CIO2 level in 2B and 2C is lower than control sample 2A.

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• 2013
  • 2013-02-06 US US13/760,657 patent/US20130206398A1/en not_active Abandoned
  • 2013-02-14 WO PCT/US2013/026013 patent/WO2013123104A1/fr not_active Ceased
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