WO2016070097A2 - Compositions d'agent de régulation des hydroxydes métalliques à ph élevé et leurs procédés d'utilisation - Google Patents

Compositions d'agent de régulation des hydroxydes métalliques à ph élevé et leurs procédés d'utilisation Download PDF

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WO2016070097A2
WO2016070097A2 PCT/US2015/058405 US2015058405W WO2016070097A2 WO 2016070097 A2 WO2016070097 A2 WO 2016070097A2 US 2015058405 W US2015058405 W US 2015058405W WO 2016070097 A2 WO2016070097 A2 WO 2016070097A2
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Prior art keywords
control agent
fluid
metal hydroxide
precipitation
proppant
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PCT/US2015/058405
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English (en)
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WO2016070097A3 (fr
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Carlos Abad
Bogdan BOCANEALA
Anastasia BIRD
Narmina FINN
Kevin Mauth
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Schlumberger Canada Limited
Services Petroliers Schlumberger
Schlumberger Technology B.V.
Schlumberger Technology Corporation
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Publication of WO2016070097A2 publication Critical patent/WO2016070097A2/fr
Publication of WO2016070097A3 publication Critical patent/WO2016070097A3/fr

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    • 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
    • C09K8/84—Compositions based on water or polar solvents
    • C09K8/86—Compositions based on water or polar solvents containing organic compounds
    • C09K8/88—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
    • 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
    • C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
    • C09K8/504—Compositions based on water or polar solvents
    • C09K8/506—Compositions based on water or polar solvents containing organic compounds
    • C09K8/508—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
    • 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
    • C09K8/52—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
    • C09K8/528—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning inorganic depositions, e.g. sulfates or carbonates
    • 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
    • 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

Definitions

  • the field to which the disclosure generally relates to is methods of using fluids in subterranean formation operations, and in particular, preparing fluids from sea water or other brines with insignificant precipitates, but which contain components prone to precipitation.
  • Hydrocarbons are obtained from subterranean geologic formations ("reservoirs") by drilling wells that penetrate the hydrocarbon-bearing formations.
  • reservoirs subterranean geologic formations
  • a pressurized fluid to provide enhanced flow path and or channels, i.e., to fracture the formation, and/or to use such fluids to transport and place proppant to facilitate flow of the hydrocarbons to the wellbore.
  • ensuring operational efficiency in the oil and gas industry promotes economical access to hydrocarbons for production.
  • high pH (basic pH) aqueous treatments have advantages over low pH (acidic pH) aqueous treatment fluids as the former are less corrosive for the metal completion equipment commonly used in the oil and gas industry.
  • high pH is not advised when using high hardness content waters (such as those with high magnesium concentration), due alkali earth hydroxide precipitation, which in some cases occurs in the form of Mg(OH) 2 .
  • compatibility between chelating agents and/or scale inhibitors using in well servicing fluids is often poor where the servicing fluids have high pH, thereby requiring suitable hydroxide precipitation control chemicals that do not affect the stability and viscosity of viscous well treatment fluids.
  • Ions most commonly found in water sources are monovalent anions such as chlorides, and bromides, and monovalent cations such as sodium or potassium, whose combinations are highly water soluble salts, accounting for the majority of the salinity in fresh, sea, or formation waters.
  • Fluorides are not commonly found in natural water sources, but can be artificially introduced in some downhole treatments of oil and gas bearing formations by means of sandstone acid treatments utilizing hydrogen fluoride, or ammonium bifluoride.
  • Fresh water sources may be a scarce resource in several environments, for instance in deserts, or in other places where the access to potable water is difficult and it should be best kept and used for human or animal consumption, or for irrigation.
  • Fresh water transport may also be very expensive, for instance transport to remote off-shore operations for which supply boats are required to transport fresh water from shore.
  • Multistage fracturing treatments may have 10 to 20 treatments to be performed on each wellbore, whereas typical stimulation vessels can transport fresh water for one or two treatments at a time.
  • alternatives to fresh water several of the available sources of non drinking water, such as brackish water, sea water, and produced water, are very high hardness waters, which contain substantial amounts of calcium and especially magnesium ions.
  • Precipitation of solids is a very undesirable process in fracturing treatment operations, since the presence of precipitates can result in substantial reduction of the main objective of a successful fracturing treatment, which is to achieve high proppant pack conductivity.
  • high magnesium containing waters can become unusable due to the expected precipitation of magnesium hydroxide at pH above about 9 to 10.
  • compatibility between chelating agents and/or scale inhibitors and high pH well servicing fluids is problematic, and finding suitable metal hydroxide control chemicals that do not affect the stability and viscosity of viscous well treatment fluids is required.
  • methods include providing an aqueous medium containing a viscosifier and one or more divalent cations prone to precipitation at a pH greater than about 8, mixing a metal hydroxide control agent with the aqueous medium to form an admixture, and adjusting the pH of the admixture to a value greater than about 8 to form an aqueous fluid of substantially basic nature, where precipitation of the divalent cations is controlled by the metal hydroxide control agent.
  • the metal hydroxide control agent is an alkali earth ion control agent, or even a magnesium hydroxide control agent, having both carboxyl and sulfonate functional groups.
  • the metal hydroxide control agent may be compliant with OSPAR requirements. Further, the pH of the admixture may be adjusted to a value greater than about 9, a value greater than about 10, a value greater than about 1 1 , or even a value greater than about 12. In another aspect, scale control may be provided downhole by the metal hydroxide control agent as pH decreases downhole.
  • the aqueous fluid is injected into a wellbore formed in a subterranean formation, and used as a fracturing fluid, gravel packing fluid, cleanout fluid, water shut-off treatment, and the like, or any combination thereof.
  • a fracturing fluid gravel packing fluid, cleanout fluid, water shut-off treatment, and the like, or any combination thereof.
  • the aqueous fluid is used in a fracturing operation, at least a portion of the aqueous fluid further includes proppant as part of the treatment fluid used in a proppant placement step of the treatment.
  • proppant may not be included in the treatment fluid as this is generally a stage prior to proppant placement.
  • Use of the fluid in fracture treatment methods may provide a proppant pack in a fracture created in the subterranean formation, where the proppant pack is essentially free of precipitation of the divalent cations from the aqueous medium.
  • Methods of use of the fluids may also include forming a gravel pack in a wellbore formed in the subterranean formation, where the gravel pack is free of precipitation of the divalent cations from the aqueous medium.
  • the wellbore is at an off-shore wellsite location, and the aqueous medium may be sea water sourced at the off-shore wellsite location.
  • methods involve providing an off-shore wellbore intersecting at least one earth formation of interest, providing a stimulation vessel with a liquid tank having a volume to store liquid water and a solid tank having a volume to store proppant, providing a design for the stimulation treatment having at least two sets of hydraulic fracturing stages, wherein each of the at least two sets of hydraulic fracturing stages includes at least one fracturing treatment, and where a total volume of a treatment fluid required to complete the at least two sets of hydraulic fracturing stages exceeds the sum of the volumes of the liquid tank and the solid tank.
  • the liquid tank can include more than one liquid tank
  • the solid tank can include more than one solid tank.
  • the liquid tank volume is filled with a sufficient amount of sea water in a volume sufficient to at least complete a first set of hydraulic fracturing stages, an optional metal hydroxide control agent is admixed with the seawater, and a first treatment fluid prepared from the sea water. Then, a first set of hydraulic fracturing stages is executed using the first treatment fluid.
  • the methods may further include replenishing the liquid tank volume with a sufficient amount of sea water surrounding the off-shore wellbore location to provide a volume of mix water stored in the liquid tank volume in an amount sufficient to perform a second set of hydraulic fracturing, admixing an optional metal hydroxide control agent with the seawater, preparing a second treatment fluid from the sea water, and performing the second set of hydraulic fracturing stages using the second treatment fluid.
  • first fractures formed are at least partially isolated in the first set of hydraulic fracturing stages, and then the second set of hydraulic fracturing stages are performed.
  • Methods may further involve filling the solid tank volume with a sufficient amount of proppant to provide a volume of proppant sufficient to at least complete the first set of hydraulic fracturing stages, and even replenishing the solid tank volume with a sufficient amount of proppant to provide a volume of proppant sufficient to at least complete the second set of hydraulic fracturing stages.
  • the sum of volume of sea water remaining in the liquid tank volume plus the volume of solid proppant volume remaining in the solid tank volume is less than a volume required to complete all stages in all subsequent sets of the stimulation treatment.
  • the first treatment fluid and the second treatment fluid prepared are sea water compatible, and preparation of the first and the second treatment fluids includes providing a hydroxide precipitation prone aqueous fluid containing or based upon sea water, admixing a fluid formula including the hydroxide precipitation prone aqueous fluid comprising sea water with (a) a concentration of the metal hydroxide control agent and a concentration of a pH adjusting agent sufficient to adjust the pH of the fluid to a value wherein metal hydroxide precipitation could be initiated in the absence of the metal hydroxide control agent, or (b) a concentration of a pH adjusting agent sufficient to adjust the pH of the fluid to a value wherein metal hydroxide precipitation could not be initiated in the absence of a metal hydroxide control agent.
  • the metal hydroxide control agent is compliant with OSPA requirements.
  • Yet another aspect provides methods of hydraulic fracturing a subterranean formation having a wellbore formed therein by preparing a fracturing fluid by providing an aqueous medium comprising a viscosifier and one or more divalent cations prone to precipitation at a pH greater than about 8, mixing a metal hydroxide control agent with the aqueous medium to form an admixture, adjusting the pH of the admixture to a value greater than about 8 to form an aqueous fluid of substantially basic nature, and completing the preparation of the fracturing fluid by adding other components.
  • Such other components may or may not include any of those materials known in the art for preparing subterranean formation treatment fluids, including, but not limited to, viscosifiers, surfactants, clay stabilizer agents, crosslinkers, delay agents, activators, non-emulsifying agents, biocides, and the like, and such components may be useful in any of the fluid and method embodiments according to the disclosure.
  • proppant may be added to at least a portion of the fracturing fluid (such as the non-PAD portion), and the fracturing fluid pumped into the wellbore at a pressure above fracturing stress value of the formation.
  • the proppant may be delivered by at least a portion of the fracturing fluid into a fracture formed in the subterranean formation, and a proppant pack formed in the fracture, which is essentially free of precipitation of the divalent cations comprised in the aqueous medium.
  • the metal hydroxide control agent is an alkali earth ion control agent including carboxyl and sulfonate functional groups, and/or the metal hydroxide control agent is compliant with OSPAR requirements.
  • methods involve preparing a dual functional aqueous fluid which includes providing an aqueous medium including a viscosifier and one or more divalent cations prone to precipitation at a pH greater than about 8, mixing a metal hydroxide control agent with the aqueous medium to form an admixture, and adjusting the pH of the admixture to a value greater than about 8 to form an aqueous fluid of substantially basic nature.
  • Precipitation of the divalent cations may be controlled by the metal hydroxide control agent, and scale controlled by the alkali earth ion control agent as pH subsequently decreases.
  • the metal hydroxide control agent is an alkali earth ion control agent comprising carboxyl and sulfonate functional groups.
  • the metal hydroxide control agent may be compliant with OSPAR requirements.
  • the dual functional aqueous fluid may be useful as an aqueous base fluid for subterranean formation treatment fluids, such as fracturing fluids, gravel packing fluids, cleanout fluids, or water shut-off treatment fluids. Some benefits provided by such a dual use fluid include minimization or prevention of precipitation of divalent cations in the form of hydroxides in high pH conditions, scale resistance post treatment once pH decreases in the subterranean environment.
  • FIG.1 shows viscosity performance of fluids formulated in examples 2.1 , 2.2, and 2.3 in Table 7, in accordance with an aspect of the disclosure.
  • FIG. 2 graphically illustrates the viscosity performance of the fluids formulated per Table 8 at 104 deg C (220 deg F), according to the disclosure
  • FIG. 3 depicts the viscosity performance of the fluids formulated per Table 8 at 1 16 deg C (240 deg F), according to an aspect of the disclosure
  • FIGS. 4 and 5 show viscosity performance of the fluids formulated as examples 3.1 through 3.6 in Table 9, in accordance with an aspect of the disclosure
  • FIGS. 6 through 13 graphically illustrates the viscosity performance of coiled tubing clean-out fluid with an AEHCA, according to an aspect of the disclosure
  • FIGS. 14 and 15 depict viscosity measurements for examples 5.1 through 5.8 to illustrate shale and acid fracturing embodiments, in accordance with some aspects of the disclosure
  • FIGS. 16 through 19 show viscosity measurements for examples 6.1 through
  • FIGS. 20 and 21 show viscosity measurements for examples 7.1 through 7.8 to illustrate viscoelastic based fluid embodiments, in accordance with some aspects of the disclosure.
  • compositions of the disclosure are described herein as comprising certain materials, it should be understood that the composition could optionally comprise two or more chemically different materials. In addition, the compositions can also comprise some components other than the ones already cited.
  • the phrase "otherwise non self- scaling aqueous fluid” refers to an aqueous fluid which contains a substantial concentration of potentially scaling divalent ions (anions and/or cations), but for which all the scale prone salts are present in concentrations below their respective saturations at the native pH of the fluid.
  • scale prone aqueous fluid refers to the chemical composition of an aqueous fluid that if prepared will undergo a process of scale deposition, and such terminology will be used to name fluids whose target cation and anion concentrations would be sufficiently high to exceed at least one salt's solubility product, and which in turn, when prepared will result in a saturated solution of said salt, and some degree of scale.
  • hydrooxide precipitation prone aqueous fluid is an otherwise non self-scaling aqueous fluid containing substantial concentrations of divalent cations that can precipitate as metal hydroxides at a sufficiently high pH.
  • alkali earth hydroxide precipitation prone aqueous fluid refers to an otherwise non self-scaling aqueous fluid containing substantial concentrations of alkali earth divalent cations that can precipitate as metal hydroxides at a sufficiently high pH, and in some embodiments, the target alkali earth cation is magnesium (Mg 2+ ).
  • scale is a solid residue, resulting from the deposition of one or various salts in an industrial or oil and gas installation resulting from flow of scale prone aqueous fluids experiencing a scale deposition process.
  • Typical scales according to the disclosure are magnesium carbonate, calcium carbonate, strontium carbonate, barium carbonate, and their mixtures, calcium sulfate, strontium sulfate, barium sulfate, and their mixtures, calcium phosphate, strontium phosphate, barium phosphate, and their mixtures.
  • scale deposition refers to the process of potential scale formation, irrespective of its extent, and or impact on the installation. Scale deposition is considered as a dynamic process whereby a scale prone aqueous fluid reaches the solubility limit of at least one of its salts at the conditions of pressure and temperature the fluid is exposed to, and therefore the excess insoluble salt is no longer soluble in the aqueous fluid. Several stages can occur during the scale deposition process.
  • nanoscopic crystals of the at least one salt are created (nucleation stage).
  • the aqueous solution may appear transparent or translucent, or exhibit some so-called Tindall effect.
  • the generated salt nuclei can grow in size by collision with other salt nuclei (growth).
  • the salt crystals become macroscopic enough for the aqueous fluid to exhibit substantial turbidity, or even appear milky.
  • some of the salt crystal can adhere to the walls of the fluid containing installation (deposition). Further growth of the deposit by subsequent addition of salt will result in the creation of a macroscopic scale.
  • scaling cations refers to medium or high atomic weight divalent alkali earth metal ions commonly present in natural water sources, that in combination with “scaling anions” can result in scale, and the terminology may apply to Ca 2+ , Sr 2+ , Ba 2+ , in some cases.
  • scaling anions refers to divalent anions commonly present in natural water sources, that in combination with “scaling cations” can result in scale, and the terminology may apply to carbonate CO3 2" , sulfate SO4 2" , phosphate, PO4 3" in some cases.
  • fluoride ions which are not typically found in natural water sources, but can be artificially introduced in some downhole treatments, in accordance with the disclosure, it will be considered that fluoride ions will be maintained for all formulations, applications, and water sources well below the limit at which they could cause substantial precipitation.
  • aqueous fluid of substantially acidic nature refers to an aqueous fluid for which the pH is lower than about 6
  • aqueous fluid of substantially basic nature refers to an aqueous fluid for which the pH is greater than about 8
  • substantially neutral aqueous fluid refers to an aqueous fluid for which the pH is between about 6 and about 8.
  • hydroxide precipitation means a process whereby grains of insoluble metal hydroxide powder will form from a hydroxide precipitation prone aqueous fluid when the metal hydroxide saturation pH is reached
  • alkali earth hydroxide precipitation means a process whereby grains of insoluble alkali earth hydroxide powder will form from an alkali earth hydroxide precipitation prone aqueous fluid when the alkali earth hydroxide saturation pH is reached, an example of which is magnesium hydroxide.
  • scale Inhibitor product refers to a chemical agent that when introduced to a scale prone aqueous fluid, may alter the scale deposition process at one or various stages of the process, such as by reducing the concentration of scaling cations available for deposition, interrupting the crystal lattice growth, preventing crystal macroscopic growth, and/or preventing crystal adherence to metals and installations, with the ultimate result of reducing substantially the scale deposition in the industrial or oil and gas installation.
  • alkali earth ion control agent -or- "AEICA” means a chemical agent that when incorporated to a alkali earth ion containing aqueous solution prone to scale deposition or prone to hydroxide precipitation can prevent at least partially one of the two mechanisms: (1 ) in scale prone aqueous solutions where in the absence of this chemical agent substantial alkali earth scale deposition would occur, the AEICA can address scale deposition; and (2) in alkali earth hydroxide precipitation prone aqueous fluid, the AEICA can prevent or minimize alkali earth hydroxide precipitation at pH values where in its absence, substantial alkali earth hydroxide precipitation would occur.
  • metal hydroxide control agent refers to a chemical agent that when incorporated to a hydroxide precipitation prone aqueous fluid can prevent or minimize hydroxide precipitation to the extent that the aqueous fluid is rendered useful, at pH where in its absence, substantial hydroxide precipitation would otherwise occur.
  • alkali earth hydroxide control agent or "AEHCA” mean a chemical agent that when incorporated to an alkali earth hydroxide precipitation prone aqueous fluid can prevent or minimize the alkali earth hydroxide precipitation at pH where in its absence, substantial hydroxide precipitation would occur.
  • the target alkali earth hydroxide precipitation prevented is magnesium hydroxide, Mg(OH)2.
  • Divalent cations commonly present in various water sources include but are not restricted to alkali earth metal divalent ions (Mg 2+ , Ca 2+ , Sr 2+ , Ba 2+ ), and transition metal cations such ad Fe 2+ , Ni 2+ , Mn 2+ , Co 2+ , Zn 2+ , Pb 2+ , Cd 2+ , and the like.
  • alkali earth metal divalent ions Mg 2+ , Ca 2+ , Sr 2+ , Ba 2+
  • transition metal cations such ad Fe 2+ , Ni 2+ , Mn 2+ , Co 2+ , Zn 2+ , Pb 2+ , Cd 2+ , and the like.
  • Scale deposition may create problems with which both the upstream and downstream oil and gas industry must manage, with significant resources for prevention and remediation.
  • Methods such as nano-filtration can result in a decrease of the anion concentration, with a process such as desulfation being used in large sea water injection projects, to prevent scale deposition derived from interaction between divalent anion rich injected sea water and divalent cation rich formation brines.
  • a saturated solution is a state of dynamic equilibrium between the dissolved, dissociated, ionic compound and the undissolved solid salt or scale.
  • the tendency and extent of the deposition for each scale forming anion cation pair can be estimated for instance as a function of their respective concentrations in aqueous fluids in comparison to a value known as solubility product constant Kps, which is a mathematical expression of the aqueous equilibrium for the specific ion pair in water.
  • Solubility product constants are used to describe saturated solutions of ionic compounds of relatively low solubility.
  • Solubility product constants are determined in pure water, under controlled laboratory conditions of pressure and temperature, and the actual value of the solubility product for each specific anion cation pair may vary depending upon temperature, pressure, gas concentration as well as on the additional compounds present in the aqueous fluid, and therefore the tabulated values should be considered as a guideline of the approximate concentrations of ions that may result in scale formation.
  • the solubility product constant is a simplified equilibrium constant (Kps) defined for the equilibrium between a depositing solid and the concentration of its forming ions in an aqueous solution.
  • the solubility product Kps of a sparsely soluble salt such as calcium sulfate does not preclude the existence of aqueous solutions with substantially higher concentrations of calcium (e.g. calcium chloride brines up to 745 g/L at 25 deg C), or sulfate (e.g. sodium sulfate brines, up to 195 g/L at 25 deg C), but prevents the presence of both ions simultaneously in an aqueous solution at concentrations whose product is larger than the Kps value.
  • calcium e.g. calcium chloride brines up to 745 g/L at 25 deg C
  • sulfate e.g. sodium sulfate brines, up to 195 g/L at 25 deg C
  • solubility product Kps may indicate or predict scale formation from a potential scale prone aqueous fluid or water source. Prevention of scale formation may be achieved by ensuring that the concentration of divalent cations (or multivalent cations in the generic case) and divalent anions (or multivalent anions in the generic case) is maintained below those required to reach the solubility product value at the given pressure and temperature of operation, or otherwise, maintaining the ion concentration below the saturation concentration.
  • scale control may involve the addition of small concentrations of either weak or strong acids such as citric acid, acetic acid, or hydrochloric acid to the aqueous fluid so as to reduce the free concentration of the scaling anion, by partial neutralization, and transforming it into a "non scaling" anion.
  • This method may also have the additional effect of substantially reducing the pH of the fluid.
  • This may be efficient when the multivalent anion involved in scale formation is carbonate, CO3 2" , sulfate SO4 2" , phosphate, PO4 3" , which would be a conjugated base of a multiprotic weak acid such as carbonic acid H2CO3, sulfuric acid H2SO4, or phosphoric acid H3PO4.
  • the protons from the added acid can partially covalently bind with the multivalent anion resulting in an increased concentration of the respective conjugated hydrogen containing anions.
  • non scaling anions obtained by partial acid neutralization of scaling anions are bicarbonate ion or hydrogen carbonate ion HCO3 " , bisulfate ion or hydrogen sulfate ion, HSO4 " , mono- hydrogen phosphate ion, HPO4 2" , and di-hydrogen phosphate ion H2PO4 " .
  • Scale control may also involve the addition of small concentrations of chemical products known as scale inhibitors.
  • Some scale inhibitor products are cation chelating chemical agents that help controlling different stages of this deposition process by preventing the accessibility of the anions to the cation, therefore disrupting the early stages of the scale deposition process, and/ or that can replace the anion in the crystal lattice disrupting further crystal and scale growth, ultimately preventing macroscopic scale formation.
  • Some chemistries useful as scale inhibitors include chemical moieties with similar structures to the scaling anions such as carboxylates, sulfonates, or phosphonates.
  • the size of the cation is sufficiently large to fit in the free volume generated in between the anionic ligand groups that chelation molecules include.
  • Small ions such as magnesium do not fit well into such free volume, but such scale inhibitors are effective to chelate cations such as Ca 2+ , Sr 2+ , and Ba 2+ .
  • alkali earth metal hydroxides are inverse to that of the respective carbonates and sulfates, with high atomic weight alkali earth metal hydroxides, such as barium and strontium hydroxides, and medium atomic weight alkali earth, calcium hydroxide, being much more soluble than low atomic weight and specially magnesium hydroxides.
  • Berilium sulfate (tetrahydrate) is very soluble (390 g /I); magnesium sulfate is considered totally soluble (255 g/l at 20 deg C, anhydrous, 710 g/l heptahydrate) but barium sulfate and strontium sulfate are very insoluble.
  • Table 3 presents the concentration of magnesium ions at which precipitation would be initiated as a function of pH in mol/L and ppm.
  • the average sea water contains about 34,700 ppm of dissolved solids, of which about 1 ,300 ppm is Mg 2+ , by far the most abundant cation in sea water after sodium Na + (10,800 ppm). This indicates that severe precipitation is to be observed if sea water pH is increased to above 9.
  • Another aspect is the extent of the hydroxide precipitation and/or scale formation.
  • magnesium hydroxide saturation for the average sea water containing about 1300 ppm Mg 2+ is to be observed at about pH 9.
  • pH 10 only 1 % of the magnesium present in the average sea water may remain in solution, which would indicate that about 99% of the magnesium originally present would precipitate if uninhibited sea water pH is increased up to 10, resulting in a total of 3,100 ppm of Mg(OH)2 solids.
  • Substantially basic (high pH) aqueous fluids whether low salinity ones such as fresh water, or high salinity ones, such as synthetic aqueous brines formulated to contain substantial concentrations of chloride atoms, naturally occurring formation waters, or even sea water, could be injected as downhole treatments, and are more commonly used as non reactive well servicing fluids over the substantially acidic (low pH) aqueous fluid treatments as the former are less corrosion prone downhole than the later.
  • an industry such as the fracturing industry utilizes low cost high pH fluids as the most effective solution to viscosify water and transport sand.
  • Basic pH, above 10 is required for to achieve boron mediated crosslinking of cis-hydroxyl group containing polysaccharides such as guar based fracturing fluids.
  • Embodiments according to the disclosure include compositions, and methods of using compositions, containing materials which inhibit or prevent metal hydroxide precipitation, and the chemical materials meet stringent environmental regulations, such as those enforced in the North Sea region, among other stringently regulated regions.
  • Any oilfield chemical that is used in the North Sea is registered with the respective country's regulatory body and that regulatory body assigns a rating or color classification to each chemical depending on its environmental and toxicological characteristics. Based on the chemical rating or color classification, the chemical will either be regarded as more or less acceptable or not.
  • the classification techniques vary. For example, (1 ) Norway and Denmark follow color classification for chemical products, (2) United Kingdom (UK) follows color and letter ratings for organic and inorganic chemical products respectively and (3) Netherlands follows letter categories.
  • each of the North Sea countries employs the same three ecotoxicology tests criteria to determine whether a specific chemical may be classified as acceptable.
  • These three ecotoxicology tests describe whether a chemical product features, on a component level, (1 ) ⁇ 60% biodegradation in seawater after 28 days, (2) little to no bioaccumulation potential among aquatic life (less than 3 partition coefficient (log Pow)) and (3) little to no-toxicity towards aquatic life (less than 10 mg/L).
  • the North Sea regulations are summarized below in Table 4:
  • compositions of matter relate to compositions of matter, and uses of the compositions, including i) an otherwise non self-scaling source of water containing a concentration of magnesium ions higher than about 10 ppm, at a pH higher than about 9, in conditions where magnesium hydroxide precipitation occurs; ii) an alkali earth hydroxide precipitation control agent (AEHCA) or a magnesium hydroxide precipitation control agent; and iii) a monovalent source of hydroxide ions at a concentration sufficiently high to reach a pH of at least about 9.0, about 10.0, about 1 1.0, about 12.0 or greater.
  • the alkali earth hydroxide control agent may be used with various wellbore treatment fluids including, but not limited to, borate crosslinked polymer fluids prepared with high magnesium ion concentrations for fracturing applications using sea water as an aqueous carrier fluid.
  • sea water based treatment fluids allows delivery of multiple treatments with one vessel load-out, and in turn may greatly reduce the significant conventional completion times and transportation resources consumed, with a benefit of signficantly increased efficiency of fracturing operations.
  • an effective metal hydroxide control agent such as an alkali earth hydroxide control agent, may be used with sea water based borate crosslinked viscosified fluids, or other brine based, at high pH.
  • Some methods according to the disclosure significantly reduce the wellsite equipment needs and logistical support by minimizing the volume of aqueous medium storage tanks required to conduct stimulation operations where the total volume of the designed treatment fluid, liquid and solid, required to complete stages of hydraulic fracturing exceeds the sum of onsite tank volume to store the liquid aqueous medium, and the onsite tank volume to store solid proppant, without the need for further supply of the aqueous medium from additional tanks or logistical supply equipment.
  • the methods include providing an off-shore wellbore intersecting at least one earth formation of interest, providing a stimulation vessel with a pre-determined tank volume to store liquid water and a pre-determined tank volume to store solid proppant, and providing a design for a stimulation treatment including at least two sets of hydraulic fracturing stages.
  • Each set of hydraulic fracturing treatments has at least one fracturing treatment stage, and the total volume of the designed treatment fluid (aqueous liquid plus solid) required to complete all of the first two sets of hydraulic fracturing stages exceeds the sum of the predetermined tank volume to store liquid water plus the pre-determined tank volume to store solid proppant in the stimulation vessel.
  • the vessel's liquid storage tanks are filled with a sufficient amount of sea water providing at least a sufficient volume of sea water to at least complete the first set of hydraulic fracturing stages.
  • the first set of hydraulic fracturing stages are completed, and the vessel liquid storage tanks replenished with a sufficient amount of sea water from the water surrounding the off-shore wellbore location, to provide a volume of sea water at least sufficient to complete the second set of hydraulic fracturing stages, and the second set of hydraulic fracturing stages are completed.
  • the steps of replenishing and completing may be continued until all sets of stimulation stages are conducted.
  • the source of aqueous medium stored in the stimulation vessel liquid tank may be sea water, or other brine, which is a hydroxide precipitation prone aqueous fluid.
  • Such methods may further include filling the vessel solid proppant tanks with a sufficient amount of proppant to provide a volume of proppant stored in the stimulation vessel solid tanks to at least complete the first set of hydraulic fracturing stages, and/or replenishing vessel solid proppant tank volume with a sufficient amount of proppant from a supply vessel to provide a volume of proppant stored in the stimulation vessel solid tanks at least sufficient to complete a further set of hydraulic fracturing stages.
  • the proppant may be added to fracturing treatment fluids during portions of the fracturing stages where proppant is delivered to fractures formed in the subterranean formation.
  • the phrase "completing a selected set of hydraulic fractures" includes providing a source of mix water stored in the stimulation vessel liquid tanks comprising sea water in at least a sufficient amount to complete the selected set of hydraulic fracturing stages, hydraulically connecting the stimulation vessel pumping line to the offshore wellbore, and performing the selected set of hydraulic fracturing stages in the at least one earth formation of interest intersected by the off-shore wellbore.
  • the sum of the remaining water volume plus the remaining solid proppant volume left in the tanks of the stimulation vessel after completion of all the stages in the selected set of hydraulic fracturing stages is smaller than the volume required to complete all the stages in all subsequent sets of hydraulic fracturing stages.
  • at least a source of proppant stored in the stimulation vessel solid tanks having at least a sufficient amount of proppant to complete at least the selected set of hydraulic fracturing stages is provided.
  • Completing a set of hydraulic fractures may further include at least partially isolating a completed hydraulic fracturing stage and initiating another hydraulic fracture elsewhere in the formation of interest.
  • Such isolation may be achieved by any suitable technique, including, but not limited to, setting a plug with optional perforation upstream from fracture(s) already formed, perforation ball sealers, fracture diverting pills (where the pill may contain solids, fibers, particulates, and the like), sliding sleeves, sand plug, downhole permanent completion with rig operatable diversion ports, swellable packers in open hole completions, or a multistage fracturing assembly with a hydraulic fracturing port in a coil tubing operation with re-settable straddle packers, or any combination thereof.
  • the pill may be degradable, partially degradable, non degradable, and/or retrievable or non retrievable.
  • sliding sleeves are cemented in place, or otherwise located in the wellbore with packer isolation, and frac ports activated, for example, by means of a rig, or with a pumpable dart, or ball, where the dart or ball may be degradable, partially degradable, non degradable, and/or retrievable or non retrievable.
  • Some embodiments of the disclosure are useful in multistage treatment operations.
  • the multistage treatment use systems designed to stimulate multiple stages efficiently and effectively, in cemented or uncemented wellbores, which may be orientated vertically, deviated, and horizontally, or combinations thereof.
  • the multistage treatments utilize repeated perforation and fracturing stages in cased wellbores using optimal parameters for each stage, and setting a perforation plug in each stage after fracturing.
  • a dissolvable plug may be useful to avoid expensive and time consuming milling operations and related limits on lateral length, while enabling production through degradable frac balls, used with or without degradable seats.
  • a continuous pumping stimulation approach involves isolating and stimulating multiple stages in cemented and/or uncemented wells in a single continuous operation.
  • Such techniques may involve the use isolation devices such as degradable packers, swellable packers, degradable ball sealers, swellable bonded-to-pipe packers, and the like.
  • Methods may further include formulating and preparing a stimulation fluid which is sea water compatible by providing a hydroxide precipitation prone aqueous fluid based upon sea water, or other brine, admixing the hydroxide precipitation prone aqueous fluid with an effective concentration of a metal hydroxide control agent, and adding a pH adjusting agent in sufficient amount to adjust the pH of the fluid to a value where hydroxide precipitation could be initiated in the absence of the metal hydroxide control agent.
  • the pH adjusting agent is added in sufficient amount to adjust the pH of the fluid to a value where hydroxide precipitation could not be initiated in the absence of any metal hydroxide control agent.
  • embodiments may also include using fluids for gravel packing, cleanout, acidizing, and/or water shut-off fluids, which contain a hydroxide precipitation prone aqueous fluid including sea water and/or other brine, another optional water source, a viscosifier such as a polymer and/or viscoelastic surfactant, a crosslinker, a pH adjusting agent and a metal hydroxide control agent.
  • the fluid may be formulated and prepared at a pH value where hydroxide precipitation would be initiated in the absence of any metal hydroxide control agent, and where the concentration of a metal hydroxide control agent is sufficient to minimize or otherwise prevent hydroxide precipitation.
  • the hydroxide precipitation prone aqueous fluid is an alkali earth hydroxide precipitation prone aqueous fluid
  • the metal hydroxide control agent is an alkali earth hydroxide control agent.
  • the concentration of the alkali earth hydroxide control agent useful is sufficient to partially prevent or substantially prevent any alkali earth hydroxide precipitation from forming.
  • the hydroxide precipitation prone aqueous fluid is sea water, which is a magnesium hydroxide precipitation prone aqueous fluid
  • the metal hydroxide control agent is a magnesium hydroxide control agent.
  • the metal hydroxide control agent may have a biodegradation value of at least 20% or of at least 30%, or of at least 40%, or of at least 50%, or of at least 60%, or of at least 70%, and/or a toxicity of at least LC50 >1 mg/L, or a toxicity of at least LC50 >5 mg/L, or a toxicity of at least LC50 >10 mg/L, or a toxicity of at least LC50 >20 mg/L, or a toxicity of at least LC50 >30 mg/L, or a toxicity of at least LC50 >40 mg/L.
  • methods include use of a metal hydroxide control agent which is non toxic, non bioacumulative sea water compatible biodegradable polymer complying with environmental regulations, having at least two sources of metal ligand moieties, carboxylates and sulfonates, and salts thereof, in stimulation treatments and fluids prepared from sea water, or other available brines, adjusted to a high pH where alkali earth hydroxide precipitation would occur.
  • a metal hydroxide control agent which is non toxic, non bioacumulative sea water compatible biodegradable polymer complying with environmental regulations, having at least two sources of metal ligand moieties, carboxylates and sulfonates, and salts thereof, in stimulation treatments and fluids prepared from sea water, or other available brines, adjusted to a high pH where alkali earth hydroxide precipitation would occur.
  • the pH is above 8.5 where carboxylate and sulfonate containing polymers including partially neutralized co(maleic acid-vinyl sulfonic acid) polymers, and or partially neutralized co(maleic anhydride-vinyl sulfonic) acid polymers which are partially neutralized with monovalent or divalent metal ion hydroxides, and /or environmentally acceptable organic counterion such as a water soluble protonated amine, for example, protonated triethanol amine, are used.
  • carboxylate and sulfonate containing polymers including partially neutralized co(maleic acid-vinyl sulfonic acid) polymers, and or partially neutralized co(maleic anhydride-vinyl sulfonic) acid polymers which are partially neutralized with monovalent or divalent metal ion hydroxides, and /or environmentally acceptable organic counterion such as a water soluble protonated amine, for example, protonated triethanol amine, are used.
  • Such polymers may be obtained by polymerization of mixtures of monomers where the mixture will include at least one source of monomers containing carboxylic acid moieties (such as maleic acid, fumaric acid, acrylic acid, methacrylic acid, itaconic acid, and the like), and at least one source of monomers containing sulfonic acid moieties (such as vinyl sulfonic acid, stryrene sulfonic acid, methyl stryrene sulfonic acid, allyl sulfonic acid, methallyl sulfonic acid, AMPS (2-Acrylamido-2-methylpropane sulfonate), and the like).
  • carboxylic acid moieties such as maleic acid, fumaric acid, acrylic acid, methacrylic acid, itaconic acid, and the like
  • monomers containing sulfonic acid moieties such as vinyl sulfonic acid, stryrene sulfonic acid, methyl stryren
  • the carboxylic acids, and/or the sulfonic acids are neutralized, at least partially if not completely, with a base, such as sodium hydroxide, potassium hydroxide, ammonium hydroxide, calcium hydroxide, organic amines such as monoethanol amine, diethanolamine, or triethanol amine, to yield carboxylate and sulfonate moeties.
  • a base such as sodium hydroxide, potassium hydroxide, ammonium hydroxide, calcium hydroxide, organic amines such as monoethanol amine, diethanolamine, or triethanol amine
  • the polymer may be prepared by polymerization of mixtures of monomers where the mixture includes at least one source of neutralized monomers containing carboxylic derived acid salt (carboxylate) moieties, (such as maleates, fumarates, acrylates, methacrylates, itaconates, and the like, of the relevant cations), and at least one source of neutralized monomers containing sulfonic acid derived salt (sulfonate) moieties, (such as vinyl sulfonates, styrene sulfonates, methyl styrene sulfonates, allyl sulfonates, methallyl sulfonates, AMPS (2-Acrylamido-2-methylpropane sulfonate) and the like, salts of the relevant cations).
  • carboxylic derived acid salt such as maleates, fumarates, acrylates, methacrylates, itaconates, and the like, of the relevant
  • the polymers have carboxylic acid and/or sulfonic acid moieties and/or the carboxylate salt or sulfonate salt moeties may be partially obtained by post reaction of a polymer comprising carboxylate precursors, such as hydrolysable amides, (i.e. acrylamide, methacrylamide, n-vynil pyrolidone, and the like), hydrolysable carboxylic acid esters, or hydrolysable anhydrides, and/or or combinations thereof, (i.e.
  • hydrolysable acrylates hydrolysable methacrylates, maleic anhydride, and the like
  • sulfonate precursors such as hydrolysable organic sulfonates in a basic pH environment, where the carboxylic acids and/or the sulfonic acids are not substantially protonated.
  • the polymers useful in compositions and methods according to the disclosure comply with the requirements of OSPAR (high biodegradation, low toxicity and low bioaccumulation requirements). It is noted that not all polymers, of all molecular weights, monomer compositions, and monomer structural distributions (degree of randomness, blockiness, or degrees of tacticity where relevant) result in biodegradable products, and thus biodegradable polymers are useful in some of the composition and method embodiments according to the disclosure.
  • the weight of the counterion is about 40 to 90% of the total active component of the metal hydroxide control agent, which in some aspects is an alkali earth metal hydroxide control agent, or even a magnesium hydroxide control agent, the polymers is that they do not cause substantial incompatibility with common subterranean treatment compositions, and/or molecular weight is moderate (at or below about 10,000 Dalton).
  • Metal hydroxide control agents useful in some aspects of the disclosure are polymers having the following functional structure within the polymer chain:
  • i may be hydrogen or a linear hydrocarbon chain, such as methyl, ethyl, and i may be different in each of the different repeating units
  • 2 may comprise at least one linear hydrocarbon chain, such as methylene, ethylene, propylene, butylene, a functional group such as amide (-CO(NH)- or a phenyl group
  • 3 may include at least one linear hydrocarbon chain, such as methylene, ethylene, propy
  • the metal hydroxide control agents may be illustrated by the following genric copolymer structure: where A, B, C, D, E, F, G are different types of repeating units derived from the monomeric units, in the anionic form. For each monomer A, B, C, F, and G a hydrogen atom, or a monovalent counterion M + , is associated so that the electrical charge of each monomeric unit is balanced. For each monomer D, and E, there will be one or two hydrogen atoms, one or two or monovalent counterions M + , or a divalent counterion M 2+ , so that the electrical charge of each monomeric unit is balanced.
  • Nonlimiting examples of repeating units include:
  • D Maleate, or Fumarate (two carboxylates branch off adjacent carbons in the backbone)
  • metal hydroxide control agents which are polymers, are polymers similar to or like those described in US Pat. No. 9,080,136, incorporated herein by reference in its entirety, and are useful to balance between inorganic and organic monovalent cations in aqueous fluids at substantially high concentrations of magnesium, and/or other divalent cations, in an aqueous pH environment equal to or greater than about 10.
  • Use of such polymers in a high pH and magnesium containing aqueous medium may extend the range of use of such polymers, and further enable use as antiscalants for medium and high atomic weight cation containing scales.
  • the polymers may function as low atomic weight metal hydroxide control agents.
  • the fluids may be useful as dual purpose fluids, which both control the metal hydroxide precipitation during a well servicing operation at high pH, and provide antiscalant properties during, and/or after the treatment operation is completed, where the downhole/subterranean formation pH changes to the natural pH of the subterranean formation.
  • a suitable polymer useful in some embodiments is KemEguard® 2593, a biodegradable scale control agent supplied by Kemira Oyj of Helsinki, Finland.
  • KemEguard® 2593 is a polycarboxylic acid/polysulfonate organic polymer having a molecular weigh of ⁇ 10,000, and supplied in a solution with a specific gravity of 1.34 and pH of about 6.5, which is effective for mixed sulfate scales, especially barium sulfate, under severe brine, temperature & pressure conditions.
  • This organic polymer is found useful, according to the disclosure, as an alkali earth hydroxide precipitation control agent (AEHCA) in wellbore treating formulations including a hydroxide precipitation prone aqueous medium containing a substantial amount of low atomic weight alkali earth cation (i.e. magnesium cation in some cases) which is adjusted to a pH of 10 or greater, which provides a condition at which substantial alkali earth hydroxide precipitation may occur, in addition to a scale inhibitor for low pH scale control operations.
  • AEHCA alkali earth hydroxide precipitation control agent
  • wellbore treatment fluids contain a metal hydroxide control agent, such as an alkali earth hydroxide precipitation control agent (AEHCA) to prevent alkali earth hydroxide precipitation in high pH wellbore treatments.
  • AEHCA alkali earth hydroxide precipitation control agent
  • the treatment fluid includes a non self-scaling source of water containing a concentration of a low atomic weight alkali earth ion sufficient to cause hydroxide precipitation at a pH condition between 9 and 10, or between 10 and 1 1 , or between 1 1 and 12, or between 12 and 13.5.
  • treatment fluid contains a source of hydroxide ions in a concentration sufficient to increase the pH of the formulation to said pH condition between 9 and 10, or between 10 and 1 1 , or between 1 1 and 12, or between 12 and 13.5.
  • the treatment fluid contains an alkali earth hydroxide control agent (AEHCA) in a concentration sufficient to substantially prevent hydroxide precipitations, whereby the organic counterions are at least substantially neutralized.
  • AEHCA alkali earth hydroxide control agent
  • the biodegradable alkali earth hydroxide precipitation control agent containing fluids can be formulated by neutralizing at pH above 10.
  • a biodegradable alkali earth hydroxide control agent can also be effective as a calcium, strontium and/or barium sulfate scale inhibitor at pH 3 to 9 or at a pH 5 to 7, for aqueous solutions that otherwise will be prone to hydroxide precipitation.
  • Polymeric alkali earth hydroxide control agent (AEHCA) useful in accordance with the disclosure include, but are not necessarily limited to, a copolymer, or a terpolymer having anionic functional groups such as carboxylate, sulfonate, and/or phosphonate.
  • the carboxylate may be derived from acrylic acid, methacrylic acid, fumaric acid, itaconic acid, partially hydrolyzed acrylamide, partially hydrolyzed methacrylamide, sodium or potasium acrylate, sodium or potassium methacrylate, sodium or potassium itaconate, hydrolyzed maleic anhydride, and the like.
  • the sulfonate may be derived from vinyl sulfonic acid, sodium or potassium vinyl sulfonate, allyl sulfonate, sodium or potassium allyl sulfonate, 2- Acrylamido-2-methylpropane sulfonic acid (AMPS), and the like.
  • the phosphonate may be derived from vinyl phosphonic acid, sodium or potassium vinyl phosphonate, and the like, and where the counterions of said anionic groups are partially inorganic, and partially organic in nature.
  • the polymeric alkali earth hydroxide control agents include neutralized amine components, which may promote biodegradation as evaluated according to the test commonly known as "marine BODIS".
  • "Marine BODIS” also known as Biodegradability of Insoluble Substance in Seawater, is an assessment of degradation of poorly soluble materials in the marine environment. Tests vessels are used which are closed glass bottles with a known volume of natural seawater (2/3) and air (1/3). They are shaken to ensure steady state oxygen partitioning between liquid and gas phases. The degradation is followed by weekly measurements of the biochemical oxygen demand (BOD) in the aqueous phase for a 28 day period.
  • BOD biochemical oxygen demand
  • Polymeric alkali earth hydroxide control agent used according to the disclosure may be utilized in any high pH fluid, such as weakly basic pH fracturing fluids (pH 8 - 9), moderately basic pH fracturing fluids (pH 9 - 10), moderate-high pH fracturing fluids (pH 10.0 - 1 1.0), high pH fracturing fluids (pH 1 1 - 12), very high pH fracturing fluids (pH 12 - 13.5), high pH wellbore clean out formulations, high pH sand control polymer based fluids, potentially high pH sand control VES based fluids, high pH slick water treatment fluids, gelled acidizing fluids, and the like, any of which may be prepared from sea water, or other source of water having high levels of alkali earth metal divalent ions (i.e. Mg 2+ , Ca 2+ , Sr 2+ , Ba 2+ , etc.).
  • alkali earth metal divalent ions i.e. Mg 2
  • Some fracturing fluid mixtures contain molecules of boric acid, or boron, as crosslinker.
  • boric acid or boron
  • the presence of high pH provides excess of OH " ion, and such excess displaces the reaction equilibrium to the formation of borate ions available for crosslinking with polymers present in the fracturing fluid.
  • sea water or other brines are used as the aqueous medium for fracturing fluids, the formulation has to be adjusted accordingly.
  • Sea water contains different ions, such as sodium, potassium, magnesium, and calcium at high concentrations, as discussed above. Sodium and potassium are not a big concern because all their salts are sufficiently soluble.
  • Some embodiments herein refer to products, formulations, and methods of use antiscalant(s), at high pH in aqueous fluids of substantially basic nature, with polymer fracturing fluids based on sea water.
  • the antiscalant(s) also function as an AEHCA, which are compatible with fracturing fluid formulations, to control hydroxide precipitation, while the fluid has an effective rheology profile, and being useful for multistage fracturing treatments, without further treatment, or dilution.
  • Fluids useful according to the disclosure include a viscosifier that may be a polymer that is crosslinkable, such as a polymer mixed with one or more sources of boron or other suitable crosslinker, and in some embodiments, a viscoelastic surfactant as an optional or alternative viscosifier.
  • suitable polymers include guar gums, high-molecular weight polysaccharides composed of mannose and galactose sugars, or guar derivatives such as hydroxypropyl guar (HPG), carboxymethyl guar (CMG), and carboxymethylhydroxypropyl guar (CMHPG).
  • Cellulose derivatives such as hydroxyethylcellulose (HEC) or hydroxypropylcellulose (HPC) and carboxymethylhydroxyethylcellulose (CMHEC) may also be used.
  • Any useful polymer may be used in either crosslinked form, or without crosslinker in linear form.
  • Xanthan, diutan, and scleroglucan, three biopolymers, have been shown to be useful as viscosifying agents.
  • Synthetic polymers such as, but not limited to, polyacrylamide and polyacrylate polymers and copolymers are used typically for high-temperature applications.
  • Nonlimiting examples of suitable viscoelastic surfactants useful for viscosifying some fluids include cationic surfactants, anionic surfactants, zwitterionic surfactants, amphoteric surfactants, nonionic surfactants, and combinations thereof.
  • associative polymers for which viscosity properties are enhanced by suitable surfactants and hydrophobically modified polymers can be used, such as cases where a charged polymer in the presence of a surfactant having a charge that is opposite to that of the charged polymer, the surfactant being capable of forming an ion- pair association with the polymer resulting in a hydrophobically modified polymer having a plurality of hydrophobic groups, as described in published application U.S. 20040209780A1 , Harris et. al., incorporated herein by reference thereto.
  • the viscosifier is a water-dispersible, linear, nonionic, hydroxyalkyi galactomannan polymer or a substituted hydroxyalkyi galactomannan polymer.
  • useful hydroxyalkyi galactomannan polymers include, but are not limited to, hydroxy-Ci-C4-alkyl galactomannans, such as hydroxy-Ci-C4-alkyl guars.
  • hydroxyalkyi guars include hydroxyethyl guar (HE guar), hydroxypropyl guar (HP guar), and hydroxybutyl guar (HB guar), and mixed C2-C4, C2/C3, C3/C4, or C2/C4 hydroxyalkyi guars. Hydroxymethyl groups can also be present in any of these.
  • substituted hydroxyalkyi galactomannan polymers are obtainable as substituted derivatives of the hydroxy-Ci-C4-alkyl galactomannans, which include: 1 ) hydrophobically-modified hydroxyalkyi galactomannans, e.g., Ci-Cis-alkyl- substituted hydroxyalkyi galactomannans, e.g., wherein the amount of alkyl substituent groups is preferably about 2% by weight or less of the hydroxyalkyi galactomannan; and 2) poly(oxyalkylene)-grafted galactomannans (see, e.g., A. Bahamdan & W.H. Daly, in Proc.
  • hydrophobically-modified hydroxyalkyi galactomannans e.g., Ci-Cis-alkyl- substituted hydroxyalkyi galactomannans, e.g., wherein the amount of alkyl substituent groups is preferably about 2% by weight or less of the
  • Poly(oxyalkylene)-grafts thereof can comprise two or more than two oxyalkylene residues; and the oxyalkylene residues can be C1-C4 oxyalkylenes.
  • Mixed-substitution polymers comprising alkyl substituent groups and poly(oxyalkylene) substituent groups on the hydroxyalkyi galactomannan are also useful herein.
  • the ratio of alkyl and/or poly(oxyalkylene) substituent groups to mannosyl backbone residues can be about 1 :25 or less, i.e. with at least one substituent per hydroxyalkyi galactomannan molecule; the ratio can be: at least or about 1 :2000, 1 :500, 1 :100, or 1 :50; or up to or about 1 :50, 1 :40, 1 :35, or 1 :30.
  • Combinations of galactomannan polymers according to the disclosure can also be used.
  • galactomannans comprise a polymannose backbone attached to galactose branches that are present at an average ratio of from 1 :1 to 1 :5 galactose branches:mannose residues.
  • Preferred galactomannans comprise a 1 ⁇ 4-linked ⁇ -D-mannopyranose backbone that is 1 ⁇ 6-linked to oD-galactopyranose branches.
  • Galactose branches can comprise from 1 to about 5 galactosyl residues; in various embodiments, the average branch length can be from 1 to 2, or from 1 to about 1.5 residues.
  • Preferred branches are monogalactosyl branches.
  • the ratio of galactose branches to backbone mannose residues can be, approximately, from 1 :1 to 1 :3, from 1 :1 .5 to 1 :2.5, or from 1 :1.5 to 1 :2, on average.
  • the galactomannan can have a linear polymannose backbone.
  • the galactomannan can be natural or synthetic. Natural galactomannans useful herein include plant and microbial (e.g., fungal) galactomannans, among which plant galactomannans are preferred.
  • legume seed galactomannans can be used, examples of which include, but are not limited to: tara gum (e.g., from Cesalpinia spinosa seeds) and guar gum (e.g., from Cyamopsis tetragonoloba seeds).
  • tara gum e.g., from Cesalpinia spinosa seeds
  • guar gum e.g., from Cyamopsis tetragonoloba seeds.
  • embodiments of the disclosure may be described or exemplified with reference to guar, such as by reference to hydroxy-Ci-C4- alkyl guars, such descriptions apply equally to other galactomannans, as well.
  • the polymer viscosifier may be present at any suitable concentration.
  • the polymer can be present in an amount of from about 10 to less than about 60 pounds per thousand gallons of liquid phase, or from about 15 to less than about 40 pounds per thousand gallons, from about 15 to about 35 pounds per thousand gallons, 15 to about 25 pounds per thousand gallons, or even from about 17 to about 22 pounds per thousand gallons.
  • the polymer can be present in an amount of from about 10 to less than about 50 pounds per thousand gallons of liquid phase, with a lower limit of polymer being no less than about 10, 1 1 , 12, 13, 14, 15, 16, 17, 18, or 19 pounds per thousand gallons of the liquid phase, and the upper limited being less than about 50 pounds per thousand gallons, no greater than 59, 54, 49, 44, 39, 34, 30, 29, 28, 27, 26, 25, 24, 23, 22, 21 , or 20 pounds per thousand gallons of the liquid phase. In some embodiments, the polymers can be present in an amount of about 20 pounds per thousand gallons.
  • Fluids incorporating polymer based viscosifiers may have any suitable viscosity, such as a viscosity value of about 50 mPa-s or greater at a shear rate of about 100 s ⁇ 1 at treatment temperature, about 75 mPa-s or greater at a shear rate of about 100 s ⁇ ⁇ and even about 100 mPa-s or greater.
  • proppants or gravel are included in fluids and methods of using the fluids, according to the disclosure.
  • Any proppant or gravel can be used, provided that it is compatible with aqueous medium, the formation, the treatment fluid, and the desired results of the treatment.
  • Such proppants, or gravels can be natural or synthetic, coated, or contain chemicals, and more than one can be used sequentially or in mixtures of different sizes or different materials.
  • Proppants and gravels in the same or different wells or treatments can be the same material and/or the same size as one another and the term "proppant" is intended to include gravel in this discussion.
  • the proppant used will have an average particle size of from about 0.15 mm to about 2.5 mm, more particularly, but not limited to typical size ranges of about 0.25-0.43 mm, 0.43-0.85 mm, 0.85-1.18 mm, 1.18-1.70 mm, and 1.70-2.36 mm.
  • the proppant will be present in the slurry in a concentration of from about 0.12 kg proppant added to each L of carrier fluid to about 3 kg proppant added to each L of carrier fluid, preferably from about 0.12 kg proppant added to each L of carrier fluid to about 1.5 kg proppant added to each L of carrier fluid.
  • a viscoelastic surfactant is used as a viscosifying agent.
  • the VES may be selected from the group consisting of cationic, anionic, zwitterionic, amphoteric, nonionic and combinations thereof. Some nonlimiting examples are those cited in U.S. Patents 6,435,277 (Qu et al.) and 6,703,352 (Dahayanake et al.), each of which is incorporated herein by reference.
  • the viscoelastic surfactants when used alone or in combination, are capable of forming micelles that form a structure in an aqueous environment that contribute to the increased viscosity of the fluid (also referred to as "viscosifying micelles"). These fluids are normally prepared by mixing in appropriate amounts of VES suitable to achieve the desired viscosity. The viscosity of VES fluids may be attributed to the three dimensional structure formed by the components in the fluids. When the concentration of surfactants in a viscoelastic fluid significantly exceeds a critical concentration, and in most cases in the presence of an electrolyte, surfactant molecules aggregate into species such as micelles, which can interact to form a network exhibiting viscous and elastic behavior.
  • suitable viscoelastic surfactants useful for viscosifying some fluids include cationic surfactants, anionic surfactants, zwitterionic surfactants
  • Embodiments of the disclosure may also include placing proppant particles that are substantially insoluble in the fractures formed in the formation.
  • Proppant particles carried by the treatment fluid remain in the fracture created, thus propping open the fracture when the fracturing pressure is released and the well is put into production.
  • Proppant may be selected based on the rock strength, injection pressures, types of injection fluids, or even completion design.
  • the proppant materials include, but are not limited to, sand, sintered bauxite, glass beads, ceramic materials, naturally occurring materials, or similar materials. Mixtures of proppants can be used as well.
  • Naturally occurring materials may be underived and/or unprocessed naturally occurring materials, as well as materials based on naturally occurring materials that have been processed and/or derived.
  • Suitable examples of naturally occurring particulate materials for use as proppants include, but are not necessarily limited to: ground or crushed shells of nuts such as walnut, coconut, pecan, almond, ivory nut, brazil nut, etc.; ground or crushed seed shells (including fruit pits) of seeds of fruits such as plum, olive, peach, cherry, apricot, etc.; ground or crushed seed shells of other plants such as maize (e.g., corn cobs or corn kernels), etc.; processed wood materials such as those derived from woods such as oak, hickory, walnut, poplar, mahogany, etc., including such woods that have been processed by grinding, chipping, or other form of particalization, processing, etc, some nonlimiting examples of which are proppants supplied under the tradename LitePropTM available from BJ Services Co., made of walnut hulls impregnated and encapsulated with resins.
  • the fluids were prepared according to known fracturing fluid formulation designs, but excluding the viscosifier polymer, which was found to mask the solids precipitation to some extent if precipitation was to occur for a given composition. Fluids were tested under different temperatures (22 deg C and 82 deg C), unless other temperature is indicated, and at different pHs, with various scale inhibitors or alkali earth ion control agents (AEICA) and a negative control, as follows:
  • KemEguard® 2593 polycarboxylic acid/polysulfonate organic polymer.
  • very high pH fluids were prepared with sea water as base aqueous fluid, guar as a viscosifying agent, a surfactant, a non-emulsifier, KemEguard® 2593 as the AEHCA, boric acid as crosslinker, caustic soda as activator, sodium gluconate as a crosslinking delay agent, and nitrilotriethanol as iron stabilizer.
  • Table 8 shows the formulations of the guar based borate crosslinked fluids with the AEHCA.
  • the viscosity measurements at 88 deg C, 104 deg C and 1 16 deg C were carried out with or without KemEguard® 2593.
  • the concentration of KemEguard® 2593 used is 30 gal/1 OOOUSgal (30 gpt), which was sufficient to prevent precipitation at the selected pH.
  • FIG. 1 shows the viscosity performance of the fluids formulated as per examples 2.1 , 2.2, and 2.3 in Table 8 at 88 deg C (190 deg F)
  • FIG. 2 graphically illustrates the viscosity performance of the fluids formulated as per Table 8 at 104 deg C (220 deg F) for examples 2.4, 2.5, and 2.6
  • FIG. 3 depicts the viscosity performance of the fluids formulated as per Table 8 at 1 16 deg C (240 deg F) for examples 2.7, 2.8, and 2.9.
  • Fluids exhibiting a viscosity value of 50cP (mPa-s) or lower, are considered as broken and do not have sufficient proppant carrying properties.
  • Temperature is shown as the dotted line near the top of the graphical representation in this and FIGS. 2 through 5 discussed below.
  • FIG. 1 shows the viscosity performance of the fluids formulated as per examples 2.1 , 2.2, and 2.3 in Table 8 at 88 deg C (190 de
  • fracturing fluids were prepared with moderate-high pH at about 10.5, with lower amounts of guar viscosifying agent, sea water as base aqueous fluid, surfactant, clay control additive, KemEguard® 2593 as AEHCA, potassium borate as a crosslinker, caustic soda as activator, and sodium gluconate as a delay agent, in the concentrations shown in Table 9 below:
  • Viscosity measurements were carried out with or without KemEguard® 2593 added to the test fluids following two distinct temperature profiles of 38 deg C ramped up to 71 deg C (100 deg F to 160 deg F) for examples 3.1 - 3.3, and 60 deg C ramped up to 71 deg C (140 deg F to 160 deg F) for examples 3.4 - 3.6. Viscosity performances at the temperature profiles selected are shown in FIGS. 4 and 5, respectively. As can be seen from FIG.
  • sea water based fluid containing AEHCA (example 3.2 and 3.3) showed like rheology performance as sea water based fluid without AEHCA (example 3.1 ) at a temperature of 38 deg C (100 deg F).
  • a substantial viscosity drop was observed for the sea water based fluid formulated in the absence of the AEHCA (example 3.1 ) upon temperature reaching 71 deg C (160 deg F), whereas the fluids containing the AEHCS substantially maintained viscosity properties upon heating up.
  • FIG. 5 illustrates a similar trend at the 60 deg C to 71 deg C ramp up, for sea water based fluids containing AEHCA, with an even sharper decrease in viscosity characteristics for sea water based fluids not containing AEHCA.
  • biopolymer based viscous fluids were prepared which are useful with coiled tubing equipment for wellbore solids removal, under high temperatures, such as about 121 deg C to about 132 deg C (250 deg F to 270 deg F).
  • the fluids were tested at low pH and high pH, and included an ethylene glycol monobutyl ether (EGMBE) based biopolymer slurry as a viscosifying agent with sea water as base fluid, KemEguard® 2593 as AEHCA (in some samples and without in others), and potassium chloride as an additional clay control salt when required.
  • EMBE ethylene glycol monobutyl ether
  • FIG. 6 shows viscosity vs shear rate profiles at 121 deg C and low pH after 20 minutes at shear and temperature conditions for examples 4.1 , 4.2, 4.3 and 4.4;
  • FIG. 7 shows viscosity vs shear rate profiles at 121 deg C and low pH after 100 minutes at shear and temperature conditions for examples 4.1 , 4.2, 4.3 and 4.4;
  • FIG. 8 shows viscosity vs shear rate profiles at 121 deg C and low pH after 20 minutes at shear and temperature conditions for examples 4.9, 4.10, 4.1 1 and 4.12;
  • FIG. 9 shows viscosity vs shear rate profiles at 121 deg C and low pH after 100 minutes at shear and temperature conditions for examples 4.9, 4.10, 4.1 1 and 4.12;
  • FIG. 10 shows viscosity vs shear rate profiles at 132 deg C and low pH after 20 minutes at shear and temperature conditions for examples 4.5, 4.6, 4.7 and 4.8;
  • FIG. 1 1 shows viscosity vs shear rate profiles at 132 deg C and low pH after 100 minutes at shear and temperature conditions for examples 4.5, 4.6, 4.7 and 4.8;
  • FIG. 12 shows viscosity vs shear rate profiles at 132 deg C and high pH after 20 minutes at shear and temperature conditions for examples 4.13, 4.14, 4.15 and 4.16;
  • FIG. 13 shows viscosity vs shear rate profiles at 132 deg C and high pH after 100 minutes at shear and temperature conditions for examples 4.13, 4.14, 4.15 and 4.16.
  • a fifth set of examples were prepared and conducted to evaluate performance in shale and acid fracturing.
  • synthetic polymer based fluids useful for low viscosity hydraulic fracturing such as the case for shale reservoirs, and acid fracturing treatments, were prepared and evaluated for viscosity performance.
  • the fluids included a synthetic polyacrylamide / AMPS copolymer of about 2MM in molecular weight, slurried in butyl glycol, used as viscosifier (which is also an effective friction reducer), which was mixed with fresh water or sea water as the base aqueous fluid, and some samples contained KemEguard® 2593 AEHCA, as shown in Table 1 1 : Additives Fresh water KemEguard® Polyacrylamide / AMPS
  • FIGS. 14 and 15 Viscosity measurements were made at room temperature for examples 5.1 through 5.8, and the results are graphically depicted in FIGS. 14 and 15. The results indicate compatibility between the synthetic polymer slurry viscosifying / friction reducing agent and KemEguard® 2593 AEHCA.
  • FIG. 14 provides rheology data with and without AEHCA at room temperature in fresh water as per examples 5.1 , 5.2, 5.3 and 5.4
  • FIG. 15 provides rheology data with and without AEHCA at room temperature in fresh water as per examples 5.5, 5.6, 5.7 and 5.8.
  • the test data show fluid viscosity at room temperature, which is the main target temperature for these applications where fluid injection rate into the wellbore and subterranean formation are very high, and therefore minimal fluid heat-up is relevant during the period of required fluid performance, such as in the cases of shale fracturing or acid fracturing.
  • Compatibility of KemEguard® 2593 AEHCA with fresh water based synthetic polymer slurry formulations was established with different concentrations of KemEguard® 2593. Although some viscosity drop was observed for the fluid containing the AEHCA compared to that of the fluid without AEHCA, the resulting viscosity is still acceptable for the applications, and may be increased to a suitable target value with minor formulation manipulation.
  • a sixth set of examples were prepared to evaluate AEHCA as part of gravel packing fluids.
  • the fluids included a xanthan based viscosifier used for sand control services.
  • High pH value fluids were prepared using a xanthan slurry based viscosifying agent, sea water as the base fluid, and KemEguard® 2593 AEHCA.
  • Table 12 provides the constituents of the fluids: Additives Sea water KemEguard® Xanthan PH Evaluation
  • FIGS. 16 through 19 The performance of the example fluids is shown in FIGS. 16 through 19.
  • FIG. 16 compares the sea water fluid with and without KemEguard® 2593 AEHCA at 25 deg C for examples 6.1 and 6.2
  • FIG. 17 compares the sea water fluid with and without KemEguard® 2593 AEHCA at 55 deg C for examples 6.3 and 6.4
  • FIG. 18 compares the sea water fluid with and without KemEguard® 2593 AEHCA at 79 deg C for examples 6.5 and 6.6
  • FIG. 19 compares the sea water fluid with and without KemEguard® 2593 AEHCA at 107 deg C for examples 6.7 and 6.8.
  • sea water based fluids formulated with KemEguard® 2593 AEHCA showed at least as strong and robust rheology performance as those sea water based fluid formulated without KemEguard® 2593 AEHCA (examples 6.1 , 6.3, 6.5 and 6.7) at the different temperatures studied.
  • the low shear viscosity is enhanced by the addition of the AEHCA, which indicates the fluid is more tolerant to the alkali earth metal concentrations observed in sea water especially at higher temperatures in the presence of the AEHCA.
  • xanthan based fluids formulated in various monovalent brines of various densities, and brines that may comprise concentrations of alkali earth metal, such as magnesium and calcium may likely provide results similar to those encountered with sea water.
  • viscoelastic surfactant (VES) based, polymer- free fracturing and gravel packing fluids were prepared at a relatively low pH of around 6, and a high pH around 10 with using sea water as the base fluid, a surfactant and a rheology modifier additive, while KemEguard® 2593 was used as AEHCA.
  • the VES used erucic amidopropyl dimethyl betaine, is useful among a variety of VES viscosifiers, as a viscosifier as an alternative to polymer based viscosifiers.
  • Rheology of the samples was modified with aqueous solution of partially hydrolized polyvinyl acetate rheology modifier. The compositions are presented as follows in Table 13:
  • Example 8.2 1000gpt 40 gpt 9.7 gpt 500 ppm 1 ,000 ppm 1 1.08
  • Example 8.4 1000gpt 40 gpt 18.35 gpt 500 ppm 5,000 ppm 1 1.02
  • Example 8.5 1000gpt 40 gpt 26.6 gpt 500 ppm 10,000 ppm 1 1.02
  • Example 8.6 1000gpt 40 gpt 85 gpt 500 ppm 30,000 ppm 11 .3
  • Example 8.1 1 1000gpt 80 gpt 25 gpt 500 ppm 5,000 ppm 10.98
  • Example 8.12 1000gpt 80 gpt 38.85 gpt 500 ppm 10,000 ppm 10.97
  • Results are provided for the precipitation tests in Table 15 below, for precipitate observations ("None”, “Slight”, “Moderate” or “Severe") made at the 80 deg C test condition.
  • Concentrations from 5,000 ppm Mg 2+ with 40 gpt KemEguard® 2593 AEHCA at pH 1 1 (example 8.4.) showed moderate precipitation.
  • precipitation at concentrations up to 10,000ppm Mg 2+ can be minimized with AEHCA at 120 gpt (Example 8.17), and prevented at 160 gpt (Example 8.20).
  • AEHCA can prevent precipitation at higher concentrations of Mg 2+ up to 5,000 ppm, and minimize precipitation up to 10,000 ppm in 500 ppm Ca 2+ containing aqueous mediums at pH 1 1 by increasing the KemEguard® 2593 AEHCA concentration.
  • the disclosure is not only limited to subterranean treatment methods and fluids, but may also be applied to other fluids with high pH and alkali earth cations, where precipitation under high pH conditions in undesirable.
  • Some such applications include, but are not limited to, process water of a plant that treats water to render it suitable for municipal drinking water, and/or to a plant that treats municipal waste water, cement fluids, drilling fluids, aqueous coatings, chemical reactor cooling fluids, cooling tower fluids, and the like.

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Abstract

L'invention concerne des procédés comprenant les étapes consistant à utiliser un milieu aqueux contenant un agent de viscosité et un ou plusieurs cations divalents enclins à précipiter à un pH supérieur à environ 8, à mélanger un agent de régulation des hydroxydes métalliques avec le milieu aqueux pour former un mélange et à ajuster le pH du mélange sur une valeur supérieure à environ 8 pour former un fluide aqueux de nature sensiblement basique, dans lequel la précipitation des cations divalents est régulée par l'agent de régulation des hydroxydes métalliques. Dans certains cas, l'agent de régulation des hydroxydes métalliques est un agent de régulation des ions alcalino-terreux, ou même un agent de régulation des hydroxydes de magnésium, possédant à la fois des groupes fonctionnels sulfonate et carboxyle. En outre, l'agent de régulation des hydroxydes métalliques peut être conforme à la convention OSPAR. Dans un autre mode de réalisation, la lutte contre le tartre peut être assurée par l'agent de régulation des hydroxydes métalliques lorsque le pH est, par la suite, abaissé.
PCT/US2015/058405 2014-10-31 2015-10-30 Compositions d'agent de régulation des hydroxydes métalliques à ph élevé et leurs procédés d'utilisation WO2016070097A2 (fr)

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US3682224A (en) * 1970-12-17 1972-08-08 Merrill Bleyle Scale prevention agents of methacrylic acid-vinyl sulfonate copolymers for saline water evaporation
US4898677A (en) * 1986-11-10 1990-02-06 National Starch And Chemical Corporation Process for inhibiting scale formation and modifying the crystal structure of barium sulfate and other inorganic salts
US5224543A (en) * 1991-08-30 1993-07-06 Union Oil Company Of California Use of scale inhibitors in hydraulic fracture fluids to prevent scale build-up
US20030073586A1 (en) * 2001-10-03 2003-04-17 Martin Crossman Scale control composition for high scaling environments
US20120160498A1 (en) * 2010-12-23 2012-06-28 Halliburton Energy Services, Inc. Concentrated Polymer Systems Having Increased Polymer Loadings and Enhanced Methods of Use
MX342993B (es) * 2013-04-25 2016-10-13 Inst Mexicano Del Petróleo Proceso de obtencion de copolimeros aleatorios derivados del acido itaconico y/o sus isomeros y alquenil sulfonatos de sodio y uso del producto obtenido.
US8833456B1 (en) * 2013-05-10 2014-09-16 Seawater Technologies, LLC Seawater transportation for utilization in hydrocarbon-related processes including pipeline transportation

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