Producing barium sulfate and fracturing fluids by mixing produced water with seawater.

Abstract

A system and method for producing base water and precipitate including combining produced water with seawater to precipitate barium in the produced water and barium sulfate from sulfates in the seawater, and separating the precipitate to obtain base water and precipitate. The base water may have less than a certain amount of sulfates and may be utilized for hydraulic fracturing fluids. The precipitate may be a weight agent for drilling.

Description

[Technical field]

[0001] This application claims priority to U.S. Patent Application No. 17 / 347,053, filed June 14, 2021, the entire contents of which are incorporated herein by reference.

[0002] This disclosure relates to produced water, seawater and fracturing fluids. [Background technology]

[0003] Hydraulic fracturing uses fluids and materials to create fractures in subterranean formations to stimulate production from oil and gas wells. Hydraulic fracturing is a wellbore stimulation technique in which underground rocks are fractured by pressurized fluids, which can be fracturing fluids. The process can include pressurized injection of fracturing fluids into the wellbore to generate fractures in deep rock formations through which natural gas, oil, and brine can flow more freely. Fracturing creates pathways that increase the rate at which production fluids, typically crude oil or natural gas, can be produced from the reservoir. When pressure in the wellbore is reduced during hydrocarbon production, proppants may be used to maintain the fractures. Proppants can resist formation closure stresses to keep the fractures open. Hydraulic fracturing may enable the recovery of crude oil and natural gas from unconventional formations that geologists once thought impossible to produce.

[0004] A way to further increase hydrocarbon production is through tertiary recovery, also known as Enhanced Oil Recovery (EOR). EOR increases the amount of crude oil or natural gas that can be extracted from a reservoir or formation. EOR is usually more expensive to use in the field than conventional recovery, but it can increase production from a well. EOR or tertiary recovery can extract crude oil from an oil field that cannot be extracted in other ways. There are various technologies for EOR or tertiary recovery.

[0005] Flowback water may be collected. This flowback water may include water injected during hydraulic fracturing, EOR, and other applications. Additionally, produced water may be present in the hydrocarbons (e.g., including crude oil and / or natural gas) typically received at the wellhead during production. Produced water may be saline water that is produced with the hydrocarbons. The produced water may be separated from the hydrocarbons and collected. Over the life of a well, produced water is generally significantly greater in volume than flowback water. Summary of the Invention

[0006] One aspect relates to a method for producing base water for hydraulic fracturing fluids and producing barium sulfate, the method including treating produced water to remove oil from the produced water, remove calcium and magnesium from the produced water, and combining the produced water with seawater to obtain a mixture, the method including precipitating barium sulfate in the mixture from barium in the produced water and sulfates in the seawater, separating the precipitated barium sulfate from the mixture to obtain base water for the hydraulic fracturing fluid, separating the base water containing less than a certain concentration of sulfates, and recovering the separated barium sulfate to obtain barium sulfate as a weight agent for a drilling fluid.

[0007] Another aspect is a method of producing base water for a hydraulic fracturing fluid and producing barium sulfate, comprising combining produced water containing barium with seawater to obtain a mixture, the produced water being water produced from a subterranean formation during the production of hydrocarbons from the subterranean formation. The method includes precipitating barium sulfate in a mixture from barium in the produced water and sulfates in the seawater to obtain a precipitate comprising barium sulfate. The method includes separating the precipitate from the mixture to obtain base water for the hydraulic fracturing fluid, the base water comprising less than a specified maximum concentration of sulfates. The method includes providing the separated precipitate to obtain barium sulfate as a weighting agent for the drilling fluid.

[0008] Yet another aspect is a method of producing base water for a hydraulic fracturing fluid and producing barium sulfate. The method includes combining produced water containing barium with seawater to obtain a mixture, the produced water being water produced from a subterranean formation. The method includes precipitating barium sulfate in the mixture from sulfates in the barium and seawater, and separating the precipitated barium sulfate from the mixture to obtain base water for the hydraulic fracturing fluid, the base water being below a sulfate concentration threshold. The method includes providing the separated barium sulfate to obtain drilling grade barite as a weighting agent for the drilling fluid. The method includes specifying an amount of seawater to be combined with the produced water as a function of the barium concentration in the produced water.

[0009] The details of one or more embodiments are set forth in the accompanying drawings and the description below. Other features and advantages will become apparent from the description and drawings, and from the claims. [Brief description of the drawings]

[0010] [Figure 1] This is a plot of the solubility of CaSO4 in water versus temperature.

[0011] [Diagram 2] This is a plot of the solubility of BaSO4 in water versus temperature.

[0012] [Figure 3A] FIG. 1 illustrates a method for producing water as a fracturing fluid base and BaSO4(s) as a product.

[0013] [Figure 3B] FIG. 1 shows a production system that produces water as a fracturing fluid base and solid BaSO4(s) as a product.

[0014] [Figure 4] Sediment mass and saturation ratio (SR) for mixtures of produced water (PW) and seawater are plotted as a function of the % seawater in the mixture. [Figure 4A] Sediment mass and saturation ratio (SR) for mixtures of produced water (PW) and seawater are plotted as a function of the % seawater in the mixture.

[0015] [Diagram 5] Sediment mass and SR for mixtures of PW and nanofiltered seawater are plotted as a function of the % seawater (nanofiltered) in the mixture.

[0016] [Figure 6] The mass of sediment and SR for the PW mixtures are plotted as a function of the % seawater in the mixture.

[0017] [Figure 7] FIG. 1 is a block flow diagram of a process that produces product base water (for hydraulic fracturing fluids) and also produces product barium sulfate. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0018] Concerns about depleting freshwater resources have created a need to develop technologies to utilize available seawater for various oilfield applications. For example, hydraulic fracturing can require millions of gallons of water per treatment, and alternative water sources are sought. One of the main problems associated with directly using seawater without treatment is the presence of sulfate ions in seawater. Sulfate ions, present in the rocks of the subsurface formation when injected into the well, can react with certain cations present in the formation brine to produce scales such as calcium sulfate or barium sulfate. This solid precipitate can have detrimental effects on the subsurface formation. Sulfates introduced into the well (by seawater injection) can also result in the production of toxic hydrogen sulfide (H2S).

[0019] Some aspects of the present disclosure are directed to a technique for removing sulfate from seawater and simultaneously producing barite (barium sulfate). By mixing produced water (having barium) with seawater (containing a hydrocarbon production site), sulfate is removed from the seawater via precipitation, resulting in a fracturing fluid base minus the precipitated sulfate. An advantage would be the synergy of both barium sulfate (e.g., for use as drilling barite) and fracturing fluid base being produced simultaneously in the same production. Additionally, as shown, the production of barium sulfate and the production of the fracturing fluid base may occur at the hydrocarbon production site.

[0020] The base or water base of the fracturing fluid may be the main component of the fracturing fluid. Additives intended to adjust the base for hydraulic fracturing of subsurface formations may be added to the base to obtain the fracturing fluid. Fracturing fluids are sometimes referred to as frac fluids or fracking fluids.

[0021] The technology can mix barium (Ba) from produced water with seawater (e.g., Arabian Gulf seawater) to produce both drilling grade barite (BaSO4) for drilling in the oil and natural gas industry and water (low sulfate) for fracturing activities. The utilized produced water can refer to associated and non-associated water present in subsurface formations that reach the surface when producing hydrocarbons.

[0022] When seawater is utilized for hydraulic fracturing of hydrocarbon-containing zones (eg, the Middle East region of the world), sulfates are removed from the seawater before it is used for hydraulic fracturing of oil and natural gas formations.

[0023] Combination of produced water (PW) (if it has sufficient barite) with seawater can produce BaSO4(s) as a solid precipitate, which is commonly used as a weighting agent for most or all types of drilling fluids. This solid precipitate can be easily separated and recovered from the water. Thus, the treated water can be the combination of PW and seawater minus the removed precipitated BaSO4(s). The treated water approaches barium and sulfate free, which makes it suitable as a base fluid for hydraulic fracturing of tight oil and natural gas reservoirs in unconventional (shale) formations for hydrocarbon production. The treated water can also be an injection fluid for enhanced oil recovery (EOR) in conventional and unconventional reservoirs.

[0024] The mixing of the produced water and seawater may include multiple preparation steps. In other words, both feedwater streams (PW and seawater) may be pretreated. The PW may be treated for oil and particulate removal. Particulate removal may lower the Total Suspended Solids (TSS) in the PW. It may also be beneficial to treat the seawater so that it is generally particulate-free. The mixing of the PW and seawater streams may be performed at thermodynamic conditions that produce sulfate precipitates. The sulfate precipitates may then be separated from the mixed water. Again, embodiments may produce both valuable barite and fracturing quality water contemporaneously (e.g., simultaneously) in the same process.

[0025] This technology can specify beneficial mixing ratios between Ba (in PW) and sulfate (in seawater) to recover usable seawater and formation water for fracturing operations in unconventional oil and gas resources. Embodiments may also use in situ processing of flowback water utilized during hydraulic fracturing operations. "In situ" processing can refer to processing at the surface of the well and can be performed in real time as the flowback water is received. The flowback water (with barium) can be pre-treated (if necessary) and mixed with seawater to provide base water for fracturing fluids.

[0026] Mixing of PW with seawater can result in the formation of precipitates. For example, the cations barium (Ba), strontium (Sr), and calcium (Ca) in the produced water can react with the anion sulfate (SO4) in the seawater to form precipitates. These precipitation reactions produce solid precipitates, producing barium sulfide (BaSO4), strontium sulfate (SrSO4), and calcium sulfate (CaSO4). BA 2+ +SO4 2- =BaSO4(s) Sr 2+ +SO4 2- =SrSO4(s) Ca 2+ +SO4 2- =CaSO4(s).

[0027] These three chemical reactions for precipitation by mixing of PW with seawater generally do not require special conditions of pressure and temperature. Instead, the reactions can occur at pressures and temperatures present in ambient ranges, mild industrial processes, or subsurface reservoir conditions. The likelihood and severity of these precipitates and associated scale formation can be evaluated.

[0028] For example, as shown in Figure 1, CaSO4(s) is unlikely to form at water temperatures below 40° C. The experimental results shown in Figure 1 confirm that CaSO4 remains in dissolved form at typical ambient temperatures below 35° C. (and ambient pressure of 1 atmosphere).

[0029] FIG. 1 is a graph 100 of the solubility of CaSO4 in parts per million (ppm) in water versus water temperature (°C). The use of "ppm" herein generally means by weight. Two curves 102 and 104 are shown. The solubility of CaSO4 increases with decreasing temperature. Curve 102 is for water with a concentration of calcium cations of 30,000 ppm. As the temperature is decreased to 40°C, curve 102 approaches the solubility of 30,000 ppm of CaSO4, showing that no CaSO4 is produced when the temperature is decreased to 40°C. Curve 104 is for water with a concentration of calcium cations of 7,000 ppm. As the temperature is decreased to 40°C, curve 104 approaches the solubility of 7,000 ppm of CaSO4, showing that no CaSO4 is produced when the temperature is decreased below 40°C. The calcium concentration was measured by atomic absorption spectroscopy.

[0030] On the other hand, precipitates of BaSO4(s) form readily at ambient temperature (and pressure). To illustrate this, Figure 2 shows the solubility of BaSO4 measured at various temperatures at ambient pressure (1 atm).

[0031] FIG. 2 is a graph 200 of the solubility of BaSO4 (ppm) in water versus water temperature (°C). Two curves 202 and 204 are shown. The solubility of BaSO4 decreases with decreasing temperature. Curve 202 is for water with a barium cation concentration of 2,200 ppm. When the temperature is decreased to 40°C, curve 302 falls well below the solubility of 2,200 ppm of BaSO4. Curve 204 is for water with a calcium cation concentration of 250 ppm. When the temperature is decreased to 40°C, curve 204 falls well below the solubility of 250 ppm of BaSO4. The experimental data shown in FIG. 2 indicates that BaSO4(s) forms (precipitates) at typical ambient temperatures below 35°C (and at an ambient pressure of 1 atm). The barium concentration was measured by atomic absorption spectroscopy.

[0032] Also, SrSO4(s) is unlikely to form below 40°C unless significant sulfate remains in the water after BaSO4 formation. Below is an overview of possible precipitates that may occur when seawater and product are mixed. Calcium carbonate [CaCO3(s)] and magnesium hydroxide [Mg(OH)2(s)] are discussed as possible precipitates in addition to the three above.

[0033] CaCO3(s) is likely to be produced, but the amount may be limited by the bicarbonate (CO3) concentration. The CO3 in the mixture is generally derived from seawater. The CO3 concentration in seawater is typically relatively low, e.g., less than 150 ppm. In an embodiment, when the seawater and PW mixture is less than 30 volume percent (vol%) of seawater, precipitation of CaCO3(s) can remove less than 1% of the Ca in the mixture.

[0034] Mg(OH)2(s) is generally not produced unless the pH is 10.3 or higher. Thus, precipitation of Mg(OH)2(s) is unlikely. Thus, Mg (or most of the Mg) may remain dissolved, typically in ionic form. Generally, little or no precipitation of MgSO4 is expected; that is, the Mg ion concentration in water is low compared to Ca and Ba, and the solubility of MgSO4 is also much greater than CaSO4 and BaSO4. Under these conditions, MgSO4 is not produced (or is expected to be produced).

[0035] BaSO4(s) may be produced, typically in the highest concentration in the precipitate. The reaction rate for the production (precipitation) of BaSO4(S) is generally fast at ambient temperatures. At temperatures higher than ambient (e.g., 100°C), the production of BaSO4(s) may dominate compared to the production of CaSO4(s).

[0036] SrSO4(s) is generally not produced in significant concentrations: the solubility limit of SrSO4 is much higher than that of BaSO4, and solids formation begins at concentrations much higher than the threshold. Therefore, again, it is unlikely that much SrSO4(s) would be produced in the mixture.

[0037] CaSO4(s) can be produced, but in much smaller quantities than BaSO4(s). The activation energy of CaSO4 is much higher than that of BaSO4.

[0038] Thus, taking the above into consideration, BaSO4(s) is generally the most predominant form of precipitate. CaCO3(s) may also be produced, but in much smaller amounts than BaSO4(s). The production of other precipitates can be controlled (reduced) by controlling the temperature of the mixture and the ratio of seawater to PW in the mixture.

[0039] Thus, by limiting the residual SO4 in the mixture, this technique can completely remove Ba and SO4 from the water while producing a solid precipitate highly concentrated in BaSO4(s) that meets American Petroleum Institute (API) specifications (e.g., API Standard 13A, 18th Edition) as a weighting agent for drilling fluids. Weighting agents, also known as weighting materials, can be high specific gravity, finely divided solid materials utilized to increase the density of drilling fluids. Mixing of PW with seawater can be performed in a manner that is tailored to the Ba concentration in the PW and the SO4 concentration in the seawater, advantageously reducing the concentrations of Ba and SO4 for use as a fracturing fluid base while producing BaSO4(s) as a product as a weighting agent.

[0040] Table 1 shows the typical ionic composition of Arabian Gulf seawater collected off the coast of Saudi Arabia. Concentration values ​​are given in milligrams per liter (mg / L). The concentration of each solute may vary slightly depending on the sampling location. [Table 1]

[0041] Table 2 provides examples of ionic compositions of oilfield PW (formation water), seawater (non-nanofiltered), and nanofiltered seawater that may be implemented in embodiments of the present disclosure. The purpose of nanofiltration of seawater may be to remove sulfates from the seawater and make the seawater more suitable for incorporation into the fracturing fluid without heavy scale precipitation when the fracturing fluid mixes with the formation water near the wellbore. The seawater in Table 2 is Saudi Arabian seawater, which may also be designated Arabian Seawater or Arabian Gulf Seawater. The nanofiltered seawater is nanofiltered Saudi Arabian seawater. The PW and seawater may be mixed at various volumetric concentrations (e.g., 70% PW and 30% seawater by volume). Calculations may be performed to confirm the desirability of the component concentrations and the compatibility of concentrations for a particular volumetric concentration of PW and seawater in the mixture. The compositions shown in Table 2 were utilized (tested) in the present experimental simulations described below. The ions listed in Table 2 include sodium (Na), potassium (K), chloride (Cl), and bicarbonate (HCO3) in addition to the ions listed above. [Table 2]

[0042] Formation water (produced water) is significantly higher in Ca and Ba compared to seawater, but formation water typically does not contain sufficient amounts of carbonate and sulfate alone to produce CaCO3(s) or BaSO4(s). Seawater, on the other hand, contains high concentrations of carbonate and sulfate, but seawater alone typically does not contain sufficient amounts of Ca and Ba to produce CaCO3(s) or BaSO4(s). PW is typically formation water and can include water injected from the surface that is subsequently produced (e.g., as flowback water). However, PW is distinct from flowback water. However, as discussed, embodiments are applicable to flowback water.

[0043] In an embodiment, when formation water and seawater, such as those having the compositions shown in Table 2, are mixed, ions begin to react and the first likely precipitation is CaCO3(s). However, the amount of precipitated CaCO3(s) is small because the bicarbonate (CO3) concentration is very low. This is followed by the formation of BaSO4(s), which is typically the desired precipitation. Other precipitates, such as CaSO4(s) and SrSO4(s), are also likely to occur if high enough concentrations remain for those ions. By limiting the residual sulfate concentration, these CaSO4(s) and SrSO4(s) precipitates that may be formed can be suppressed. Limiting the residual sulfate can mean utilizing most of the sulfate for the precipitation of BaSO4(s).

[0044] FIG. 3A is a method 300 for producing water 302 as a fracturing fluid base and BaSO4(s) 304 as a product. The method 300 combines (e.g., mixes) PW 306 (with barium) and seawater 308 (with sulfates) to obtain water 302 and BaSO4(s) 304 as two separate product streams. The amount of seawater 302 may be, for example, less than 30% by volume of the mixture, and thus the amount of PW 306 may be, for example, at least 70% by volume of the mixture. PW 306 may typically be generated formation water, but may also be or include flowback water. The mixture of seawater 308 and PW 306 minus precipitated BaSO4, water 302 (for fracturing fluid) approaches beneficially sulfate-free (e.g., less than 900 ppm sulfate). The process produces relatively sulfate-free base (injection) water 302 and a precipitate with a high BaSO4 concentration (BaSO4(s) 304).

[0045] In block 310 of the method, de-oiling of the PW 306 is performed to remove organic contaminants (e.g., crude oil) from the PW 306. In de-oiling, the PW 306 is separated from its organic contaminants. This can be done by different techniques including, for example, centrifugation (e.g., hydrocyclone), flotation (e.g., induced gas flotation or dissolved gas flotation), filtration (e.g., via nutshell filters or ceramic membranes), or adsorption (e.g., via activated carbon filters or polymeric adsorbents). Removal of the organic content from the PW 306 need not be complete, as some residual organic matter in the PW 306 (and thus in the water 302) may beneficially contribute to protecting the equipment from corrosion by reacting with peroxide radicals generated by the initial corrosion reaction. In some embodiments, block 310 is an optional operation of the method 300 and may not be performed.

[0046] In block 312, the deoiled PW 306 is subjected to softening. In some embodiments, block 312 is an optional operation of the method 300 and may not be performed. Water softening may be the removal of calcium, magnesium, and certain other metal cations found in hard water. In softening 312, the hardness of the PW 306 is controlled by adding sodium carbonate (Na2CO3) or sodium hydroxide (NaOH). Softening refers to removing Ca and Mg. Softening may be washing or precipitation as described herein, or via ion exchange. In precipitation as described herein, the removed Ca and Mg ions may include CaCO3 and Mg(OH)2 in aqueous solution, as indicated by reference numeral 313. Adding Na2CO3 gives CaCO3, but generally not MgCO3, because Mg is precipitated and removed by producing Mg(OH)2. Adding NaOH gives Mg(OH)2, but generally not Ca(OH)2. Ca(OH)2 is highly soluble and little or no precipitation occurs, while Mg(OH)2 is usually produced even at high pH. Techniques for softening the water may be used, for example, via precipitation as described, or by washing the PW306, or by treating the PW306 with ion exchange resins, to effect softening 312.

[0047] To prevent the PW 306 (and thus the water 302) from significantly corroding the equipment, the removal of calcium and magnesium may be partial in the softening 312. The remaining alkaline cations Ca and Mg may beneficially contribute to forming a corrosion protection layer on the metal walls. The calcium and magnesium ions in combination with the bicarbonate ions may slow the corrosion rate in the process equipment.

[0048] The reaction of peroxide radicals with organic materials and alkaline cations Ca and Mg can slow the oxidation of divalent iron, and therefore the presence of some remaining Ca and Mg ions in PW306 may have the beneficial effect of slowing the corrosion rate in equipment implementing this technology.

[0049] In block 314, the deoiled and softened PW 306 is mixed with seawater 308 at a specified operating condition temperature and pressure at a specified volume percentage of the seawater 308 to produce BaSO4(s). The seawater 308 may be non-nanofiltered or nanofiltered seawater. The seawater 308 may be treated to remove particles before mixing with the PW 306. The seawater 308 may be, for example, less than 40% or less than 30% by volume of the mixture (mixed water), for example, in the range of 10% to 40% by volume. To minimize or reduce the residual Ba and sulfate concentrations in the mixed water after removing the BaSO4(s) precipitate, the mixing of the PW 306 and seawater 308 may be specified near or at the stoichiometric ratio of Ba and sulfate, which is about 1.43 Ba to 1 sulfate on a molar basis. Different mix ratios may be used depending on the Ba concentration in the product water and the sulfate in the seawater. Embodiments may rely on PW306 (produced from subterranean formations) for the barium. Thus, embodiments may avoid adding barium (e.g., as barium chloride) to the mixture.

[0050] The mixture of (deoiled and softened) PW 306 and seawater 108 may be sent to a separation vessel to separate the precipitated BaSO4(s) solids from the mixture. For example, the mixture may be sent to a decanter vessel that allows sufficient residence time for the BaSO4(s) solids to separate by gravity. Typically, residence times of, for example, 20 minutes to 4 hours may be implemented for good separation of the precipitate suspended in the water. Due to the small size of the precipitate crystals produced, the surface averaged water velocity in the decanter or gravity separator should generally not exceed 5 centimeters (cm) per second. The surface averaged water velocity in the decanter or gravity separator may be, for example, the total water flow rate divided by the channel surface area at any orthogonal channel plane inside the decanter. ppm

[0051] For example, in some marine applications and other locations where available space is limited, filtration of the mixed water to separate the BaSO4(s) precipitate from the mixed water can be used as an alternative to gravity separation when large decanter vessels cannot be installed. The mesh size of the filter can be, for example, less than 0.5 microns (μm), or in the range of 0.1 μm to 1 μm.

[0052] The water 302 discharged from the separation vessel, such as a decanter (gravity separation vessel) or filter vessel, can be used as a fracturing fluid. Typical additives for fracturing fluids can be added to the water 302 to obtain a fracturing fluid that can be employed in hydraulic fracturing of subterranean formations. Sulfate-rich seawater 308 is used to obtain the water 302, which is low in sulfates.

[0053] The equipment used for precipitation 314 (e.g., mixing devices, decanter vessels, etc.) may be configured to reduce scaling risks while promoting bulk precipitate production. In particular, the equipment may be of non-metallic materials or have anti-scaling coatings on the interior walls. Embodiments may include implementing corrosion prevention techniques that prevent or slow oxidation of divalent iron. Additionally, scale mitigation strategies may be applied that include periodic injection of selected chemicals.

[0054] The sulfate concentration in the base water 302 will generally be the sulfate concentration in the fracturing fluid incorporating the base water 302 since the fracturing fluid mainly comprises the base water 302. The specified maximum concentration of sulfate in the water 302 that is acceptable may depend on the water chemistry of the fracturing fluid with the formation fluid of the subsurface formation subjected to hydraulic fracturing. The higher the BA, Ca, Sr concentrations in the formation water, the lower the sulfate should be in the fracturing fluid. Some sulfate in the fracturing fluid may be acceptable since anti-scalants can be added to the fracturing fluid to address the possibility of scaling in near wellbore areas, etc. The specified maximum sulfate concentration in the water 302 may be, for example, 1000 ppm, 900 ppm, 800 ppm, 700 ppm, 600 ppm, or 500 ppm. For reference, if seawater is nanofiltered, the sulfate concentration in seawater may be, for example, 200 ppm.

[0055] FIG. 3B is a production system 330 capable of implementing the method 300 of FIG. 3A. The production system 300 produces water 332 as a fracturing fluid base and also produces solid BaSO4 334 as a product. In operation, the system 330 mixes deoiled and softened PW 336 with seawater 338 to obtain water 332 and precipitated BaSO4(s) 334 as two separate product streams. Although the seawater 338 has a significant amount of sulfate, the water 332 (produced for the fracturing fluid) including the seawater 338 is beneficially close to sulfate free due to removal of sulfate via precipitation of BaSO4(s). The sulfate concentration in the water 332 may be, for example, less than 900 ppm.

[0056] The production system 300 includes a de-oiling system 340. The de-oiling system 340 receives PW 342 and outputs de-oiled PW 344. PW 342 may be water produced from a subterranean formation in the production of hydrocarbons from the subterranean formation. Thus, PW 342 may be water separated from the hydrocarbons produced from the subterranean formation. PW 342 may include Na, Cl, Ca, Mg, Ba, and Sr.

[0057] The de-oiling system 340 may include a vessel 346 for performing de-oiling of the PW 342. The organic contaminants removed in the de-oiling may include free oil and immiscible hydrocarbons more generally. The contaminants may include dissolved organics as well as solid forms. The vessel 346 may be a centrifuge or a hydrocyclone for removing the organic contaminants from the PW 342. The vessel 346 may be a flotation vessel utilized to perform induced gas flotation or dissolved gas flotation to de-oil the PW 342. The vessel 346 may be a filter vessel (housing) having a filter element for filtering the PW 342 to remove the PW 342. The filter vessel may be a nutshell filter vessel having a nutshell medium as a filter element. The filter vessel is a filter housing having a ceramic membrane as a filter element. The ceramic membrane is formed from an inorganic material and utilized in membrane operations for liquid filtration. Other filter types are also applicable. Vessel 346 may be, for example, an adsorption vessel having an activated carbon filter or polymeric adsorbent to filter and de-oil PW342.

[0058] A softening system (softener) 348 may receive the deoiled PW 344. The softening system 348 may remove ions such as calcium and magnesium from the deoiled PW 344 to soften the PW 344. The purpose of softening may be to reduce scaling (e.g., Ca, Mg mineral build-up). Softening may reduce Ca and Mg to prevent or reduce scaling (e.g., CaCO3, Mg(OH)2) in tubing, tanks, membranes, injection conduits, wells, etc. When fracturing fluids containing PW are mixed downhole with incompatible water, scaling may form on the surface of the downhole tubing and in areas near the wellbore in the underground formation (reservoir).

[0059] The softening system 348 can include a vessel 350 that removes ions that contribute to water hardness from the deoiled PW 344. The vessel 350 can be a washing vessel for washing the deoiled PW 344 to remove hardness ions. The vessel 350 can be an ion exchange vessel having ion exchange resin for removing hardness ions (e.g., Mg and Ca) from the deoiled PW 344. The softening system 348 can discharge the deoiled and softened PW 336 for addition (combination) with seawater 338.

[0060] The blending system 352 may receive the deoiled and softened PW 336 and combine the deoiled and softened PW 336 with seawater 338 to obtain a blend 354. The amount of seawater 338 for the blend 354 may be controlled to provide a specified volume percent of seawater 338 in the blend 354 or a specified volume ratio of seawater 338 to PW 336 in the blend 354. In some embodiments, a flow control valve 356 may control (e.g., maintain, adjust, modulate, etc.) the rate or amount of seawater 338 incorporated into the blend 354. In embodiments, the flow rate of the PW 336 and the flow rate of the seawater 338 may be measured by respective flow meters (not shown) disposed along the conduits carrying the PW 336 and the seawater 338, respectively. The flow rates measured by the flow meters may be indicated to the control system 358. A flow control valve may also be disposed along the conduits carrying the PW 336 to control the flow rate of the PW 336.

[0061] The amount of seawater 338 taken into the mixture 354 of seawater 338 and PW 336 is determined by the amount of barium ions (Ba 2+ ) concentration and sulfate ion (SO4 2- ) concentration. In other words, SO4 2- and Ba 2+ The molar ratio of the residual sulfate (SO4 2- ) to be low (e.g., below a particular sulfate concentration threshold) to provide a beneficial amount of BaSO4 precipitation (e.g., at or near the stoichiometric ratio).

[0062] The PW 336 (or 342, 344) can be sampled and the barium concentration measured in a laboratory. The measured barium concentration can be entered into the control system 358 by a human operator via a user interface of the control system 358. In some embodiments, an online instrument analyzer 360 (e.g., an online spectrometer) located along the conduit carrying the PW 336 (or 342, 344) measures the barium concentration in the PW 336 (or 342, 344) in real time. An instrument transmitter can indicate the barium concentration measured by the online instrument analyzer 360 to the control system 358.

[0063] The seawater 334 may be sampled and the sulfate concentration measured in a laboratory. The measured sulfate concentration may be entered into the control system 358 by a human operator via a user interface of the control system 358. In some embodiments, an online instrument analyzer 362 (e.g., an online spectrometer, an ultraviolet oxidation instrument, an ion chromatography instrument, etc.) located along a conduit carrying the seawater 338 measures the sulfate concentration in the seawater 338 in real time. An instrument transmitter may indicate the sulfate concentration measured by the online instrument analyzer 362 to the control system 358.

[0064] The product water 332 may be sampled and the sulfate concentration measured in a laboratory. The measured sulfate concentration may be entered into the control system 358 by a human operator via a user interface of the control system 358. In some embodiments, an online instrument analyzer 364 (e.g., the same as or similar to analyzer 362) located along the conduit carrying the water 332 measures the sulfate concentration in the water 332 in real time. An instrument transmitter may indicate the sulfate concentration measured by the online instrument analyzer 364 to the control system 358.

[0065] In some embodiments, the control system 358 may adjust (e.g., via the control valve 356) the amount of seawater 338 that is combined with the PW 336 in response to the barium concentration measured in the PW 336, the sulfate concentration in the seawater 338, and the sulfate concentration in the product water 332. The adjustments made by the control system 358 may be automatic. The adjustments made by the control system 358 may be real-time. The control system 358 may also (or instead) adjust the amount of PW 346 incorporated into the mixture 354.

[0066] The mixing system 352 can include a vessel 366 for combining the seawater 338 and the PW 336. The vessel 366 can be, for example, a mixing vessel equipped with an agitator or mixer to facilitate mixing of the seawater 338 and the PW 336. Precipitation of the solid BaSO4(s) 334 can occur in the vessel 366. In an embodiment, the vessel 366 can hold a relatively large volume of the mixture 354, for example a large open-to-air tank or pool, allowing for precipitation under static conditions. In other embodiments, the seawater 338 and the PW 336 can be combined in-line in a conduit. In that case, an in-line static mixer can be included in the conduit to facilitate mixing of the seawater 338 and the PW 336. Precipitation of the solid BaSO4(s) 334 can occur in the conduit. The PW can be mixed with the seawater in the piping by adding seawater (e.g., via a pipe tee) from the piping carrying the seawater to the piping carrying the PW.

[0067] The mixture 354 may be fed to a separation system 368 where solid BaSO(s) 334 is removed from the mixture 354 to obtain water 332. Precipitation of solid BaSO(s) 334 may occur within the separation system 368, depending on the embodiment.

[0068] The separation system 366 may include a separation vessel 370 for removing BaSO4(s) 334 from the mixture 354 and discharging the BaSO4(s) 334 as a product. The separation vessel 370 may also discharge water 332 (e.g., utilized as a base fluid for the fracturing fluid) as a product. The sulfate concentration in the water 322 may be, for example, less than 900 ppm. Precipitation of solid BaSO4(s) 334 may occur in the separation vessel 370 in some embodiments.

[0069] The separation vessel 370 may be a decanter vessel that allows sufficient residence time for the BaSO4(s) solids to separate by gravity. Typically, a residence time of, for example, at least 20 minutes (e.g., 20 minutes to 4 hours) may be implemented to separate the precipitate 334 in the mixture 354. In certain embodiments, the surface average water velocity inside the decanter or gravity separator may be less than 5 cm per second or less than 10 cm per second due to the relatively small size of the precipitate crystals produced as the BaSO4(s) precipitate 334. In other embodiments, the separation vessel may be a filter vessel having a filter element for separating the BaSO4(s) precipitate from the mixed water 354. The mesh size of the filter element may be, for example, less than 0.5 μm, or in the range of 0.1 μm to 1 μm.

[0070] The equipment used in the mixing system 352 and separation system 368 (e.g., mixing vessel 366, separation vessel 370, etc.) may be configured to reduce the risk of scaling while promoting the production of bulk precipitates. In particular, the equipment may be of a non-metallic material or may have a coating on its interior walls, such as polytetrafluoroethylene (PTFE), ethylene tetrafluoroethylene (ETFE) (e.g., thermoset Saekaphen®), epoxy, or Teflon®. Embodiments may include implementing corrosion prevention techniques. Additionally, scale mitigation strategies involving periodic injection of selected chemicals may be implemented.

[0071] The control system 358 can facilitate or direct the operation of the production system 300, such as supplying or discharging flows (including flow rates) and associated control valves, controlling operating temperatures and pressures, and controlling vessels, pumps, filters, etc. The control system 358 can include a processor 372 and a memory 374 that stores code (e.g., logic, instructions, etc.) executed by the processor 372 to perform calculations and direct operations of the system 300. The control system 358 can be or include one or more controllers. The processor (hardware processor) 372 can be one or more processors, each having one or more cores. The hardware processor(s) can include a microprocessor, a central processing unit (CPU), a graphics processing unit (GPU), a controller card, a circuit board, or other circuitry. The memory 374 can include volatile memory (e.g., cache and random access memory), non-volatile memory (e.g., hard drives, solid state drives, and read-only memory), and firmware. The control system 358 may include a desktop computer, a laptop computer, a computer server, a programmable logic controller (PLC), a distributed computing system (DSC), a controller, an actuator, or a control card. The controllers, including the master controller and the slave controllers, may be components of code stored in memory 374 and executed by the processor 372. The control system 358 may include control modules and devices distributed in the field.

[0072] The control system 358 may receive user inputs that specify set points for the controllers or other control components in the natural gas dehydration system 300. The control system 358 typically includes a user interface for inputting set points and other targets or constraints into the control system 358. In some embodiments, the control system 358 may calculate or otherwise identify set points for the controllers. The control system 358 may be communicatively coupled to a remote computing system that performs the calculations and provides directions, including set point values. In operation, the control system 358 may facilitate the processes of the system 300, including directing the operation of the PW 336 and seawater 338 flows to the mixing system 352. Again, the control system 358 may receive user inputs or computer inputs that specify set points for the control components in the system 100. The control system 358 may identify, calculate, or specify set points for the controllers. This determination may be based at least in part on the operating conditions of the system 300, including feedback information from sensors, meters, instruments, analyzers, transmitters, and the like.

[0073] Some embodiments may include a control room, which may be a center of activity that facilitates monitoring and control of a process or equipment. The control room may include a human machine interface (HMI), which may be, for example, a computer running specialized software to provide a user interface for the control system. The HMI may vary by vendor and may present a graphical version of a remote process to a user. There may be multiple HMI consoles or workstations, with varying degrees of access to data. The control system 358 may additionally or alternatively employ local control (e.g., distributed controllers, local control panels, etc.) distributed within the system 300.

[0074] Figures 4-6 are graphs showing simulation data obtained by ScaleSoftPitzer® (version 13.0) simulation software available from the Rice University Brine Chemistry Consortium (BCC), based in Houston, Texas, USA. ScaleSoftPitzer® is an Excel® based software program for predicting scale formation for 16 different minerals (including carbonates, sulfates, halides, sulfides, calcium fluorides, and silicates). The program is based on the Pitzer theory of electrolytes. Guideline values ​​for the interpretation of SR values ​​are given in Table 3. Precipitation can be undesirable in the context of scaling. Precipitation can give a desired precipitate that is not scaling but is collected as a product. [Table 3]

[0075] 4-6 include an axis for saturation ratio, which can be a value less than 1. Water can be unsaturated, saturated, or supersaturated. The term "saturation" ratio encompasses these conditions. The term "saturation" ratio can encompass values ​​of supersaturation.

[0076] FIG. 4 is a graph 400 of mass of precipitate (mg / l) and saturation ratio (SR) (dimensionless) for PW and seawater mixtures at 139° C. as a function of % seawater (volume %) in the mixture. SR is a unitless relative number. PW is the tested formation water from Table 2. Seawater is the (non-nanofiltered) Saudi Arabian seawater from Table 2. Thus, FIG. 4 provides a prediction of sulfate precipitation at 139° C. for the seawater and PW mixtures from Table 2. FIG. 4 shows simulated data for sulfate precipitation. The mixture temperature of 139° C. represents an example of a subsurface temperature during a hydraulic fracturing operation. As shown, the simulated data was obtained using industry standard ScaleSoftPitzer® software, which utilizes the Pitzer equation to provide a value for the supersaturation ratio (SR) of the mixed water. Supersaturation is the driving force for precipitation.

[0077] Curve 402 is the amount of BaSO4 precipitate. Curve 404 is the amount of CaSO4 precipitate. Curve 406 is the amount of SrSO4 precipitate. Curve 408 is the SR of BaSO4. Curves 410, 412 are the SR of CaSO4 and SrSO4, respectively, and generally overlap at the scale depicted. FIG. 4A is an enlargement of the lower portion of graph 400 to show the distinction between curves 410 and 412. FIG. 4 shows the possibility of relatively large amounts of precipitation of CaSO4, BaSO4, and SrSO4 due to mixing of seawater and formation water. After precipitation, there are much fewer SO4 ions in the solution than there were in the original seawater, making it more suitable for use as a fracturing fluid.

[0078] FIG. 5 shows simulated data for sulfate precipitation when mixing PW and nanofiltered Arabian seawater from Table 2 at 139° C. FIG. 5 is a graph 500 showing the mass of precipitate (mg / l) and SR for a mixture of PW and nanofiltered seawater at 139° C. as a function of the % of seawater in the mixture (volume %) (nanofiltration). Curve 502 is the amount of BaSO4 precipitate. Curve 504 is the amount of CaSO4 precipitate. Curve 506 is the amount of SrSO4 precipitate. Curve 508 is the SR of BaSO4. Curves 510, 512 are the SR of CaSO4 and SrSO4, respectively, and generally overlap to the scale depicted. FIG. 5 shows the potential precipitation using nanofiltered seawater (which has a lower concentration of SO4 ions than the seawater of FIG. 4). Using original seawater (FIG. 4) instead of nanofiltered seawater (FIG. 4) allows more BaSO4 to precipitate. When using seawater, the much higher SR (compared to nanofiltered seawater) can aid in precipitation. As mentioned before, SR is the driving force behind precipitation. Higher SR can mean faster precipitation. Nanofiltered seawater can help lower sulfates in the fracturing fluid base (compared to seawater).

[0079] Figures 4 and 5 show that significant BaSO4 precipitation and severe scaling can occur when more than a few volume percent of seawater or nanofiltered seawater is injected into a subterranean formation (a hydrocarbon reservoir having oil and / or natural gas) to hydraulically fracture the formation. For these reasons, seawater should be treated for sulfate removal before it is utilized in hydraulic fracturing operations. Conventional seawater treatment methods for use in hydraulic fracturing operations are essentially based on membrane filtration and desalination for sulfate removal.

[0080] FIG. 6 shows the results of a precipitation simulation at ambient (atmospheric) conditions. For the mixtures of (non-nanofiltered) seawater and PW in Table 2, the prediction of sulfate precipitation is at 25° C. and 1 bara absolute pressure. FIG. 6 shows a graph 600 of the mass (mg / l) and SR of precipitate at 25° C. and 1 bara as a function of the % of seawater in the mixture (volume %) for a mixture of PW and seawater. Curve 602 is the amount of BaSO4 precipitate. Curve 604 is the amount of CaSO4 precipitate. Curve 606 is the amount of SrSO4 precipitate. Curve 608 is the SR of BaSO4. Curves 610, 612 are the SR of CaSO4 and SrSO4, respectively, and generally overlap at the scale depicted.

[0081] Figure 6 shows that significant BaSO4 precipitation occurs when seawater and PW are mixed at 25 °C and 1 bara. The BaSO4 saturation ratio can be 0 to 14,352. The prominent conditions for BaSO4 precipitation at the predicted sites are mixing 10 vol% to 90 vol% seawater with corresponding 90 vol% to 10 vol% high salinity PW, with SRs of 5,101 to 14,352. This is coupled with massive precipitation of BaSO4 from 910 mg / L to 3,741 mg / L. Relatively high BaSO4(s) formation rates can occur when PW and seawater are mixed in such volume ratios under ambient conditions.

[0082] For CaSO4, when seawater and high salinity PW are mixed at 25°C and 1 bara, the SR is 0-2. The CaSO4 solution is slightly supersaturated. The potential for CaSO4 scaling is low.

[0083] For SrSO4, when seawater and high salinity PW are mixed at 25°C and 1 bara, the SR is 0 to 9. SrSO4 scale precipitation can occur but is generally not serious.

[0084] These results illustrate how drilling grade barite can be easily obtained by embodiments of the present technology. The volume ratio of mixed seawater and PW can be adjusted to control the formation of BaSO4(s) precipitate.

[0085] In general, pressure does not have a significant effect on the SR or scaling tendency of sulfates. This is shown in Table 4, where the predicted characteristic parameters of BaSO4 precipitation are reported at 1 bara and 10 bara, respectively, for the water compositions in Table 2. The data in Table 4 show that the SR changes very little between 1 bara and 10 bara. The precipitation rate of BaSO4(s) does not change. [Table 4]

[0086] The volume ratio of seawater to PW, as well as the mixing temperature, can be adjusted to control the formation of BaSO4(s) precipitate. The present technology can generally be implemented at operating pressures below 50 bara. Furthermore, unlike membrane-based methods for sulfate removal, embodiments herein can be integrated without loss of performance in sulfate precipitation where pressures can vary between 1-10 bara over time.

[0087] Sulfate removal efficiency is a variable to adjust or optimize to fine-tune an embodiment. Table 5 shows the calculated sulfate remaining in the mixed seawater and product water after complete BaSO4 precipitation for the water compositions shown in Table 2. [Table 5]

[0088] As an example of fine-tuning the technology using the particular mixed water considered above (water composition in Table 2) as an example, the results in Table 5 confirm that mixing 10% to 40% by volume of seawater with corresponding 90% to 60% by volume of high salinity PW can reduce sulfate concentrations in the mixed water to below 500 ppm. Thus, for the feedwater considered in this example, operation with a volume ratio of (e.g., non-nanofiltered) seawater to PW in the range of 10% to 40% can be beneficial for increasing the production of high quality barite as well as water for hydraulic fracturing applications. The precipitate produced and recovered is BaSO4 micronized to meet API Standard 13A (18th Edition) and can be utilized to increase mud density in drilling fluid systems (oil-based or water-based).

[0089] The present technology may also be utilized to treat flowback water for reuse at hydraulic fracturing sites. During hydraulic fracturing operations, a relatively large amount of water that has come into contact with the formation flows back to the surface. This flowback water is typically either disposed of or treated for reuse, depending on the contaminants in the flowback water. If the Ba concentration in the flowback water is significant, embodiments herein may be advantageously utilized (e.g., at a well site) to mix the flowback water with seawater to provide fracturing fluid, so that the flowback water can be reused in hydraulic fracturing operations.

[0090] The technology can produce high-quality water for use as a fracturing fluid in unconventional oil and gas production operations, and can simultaneously produce barite (BaSO4(s)) for drilling. The specific gravity of pure barium sulfate is 4.50 grams per cubic centimeter (g / cm 3 ), but to meet API standards, including API Standard 13A (18th Edition), mined barite has a density of about 4.20 g / cm 3 The embodiments of the technology herein provide a specific gravity of 4.20 g / cm for the precipitated and separated barium sulfate. 3Furthermore, Ca is generally removed during the softening step, and thus the separated precipitate is typically primarily BaSO4, e.g., at least 85 wt. % BaSO4. This technique is, for example, primarily barium sulfate, with a target specific gravity of 4.20 g / cm 3 The softening of the produced water and the amount of seawater added can be adjusted to obtain a precipitate with a specific gravity of 0.01%. Barium sulfate meeting API Standard 13A (18th Edition) can be labeled as drilling grade barite. Barite meeting API Standard 13A (18th Edition) can be labeled as drilling grade barite.

[0091] The embodiment may provide flexibility to supply water for hydraulic fracturing at various flow rates and typical pressures to meet the needs of hydraulic fracturing operations. Unlike membrane-based technology (traditional seawater treatment), the process according to the present embodiment can adjust the production flow rate of base water for fracturing fluid in real time and can be easily put on standby without risk of fouling or damage to equipment. Compared to the prior art, the implementation of the present method is cost-effective in removing sulfate from seawater because it does not require membrane cleaning or regular maintenance.

[0092] Embodiments of the present technology can facilitate controlled precipitation and separation of unwanted ions in seawater and PW. Embodiments can utilize high salinity PW containing relatively high concentrations of Ba and Ca ions to remove sulfates in seawater, where membranes are not implemented or required. The present technology can provide an alternative to membrane filtration for removing sulfates from seawater. The present technology can provide a solution for treating and reusing flowback water from hydraulic fracturing operations. Certain embodiments do not use fresh water as the water content produced as base for fracturing fluids. Additionally, embodiments can provide a cost-effective solution for locally generating base water and drilling grade BaSO4(s) at oil and natural gas production facilities, including well sites where hydrocarbons are produced from subsurface formations through wells.

[0093] The well site can utilize the generated base water for fracturing fluid. The process can be flexible in that it can be adjusted in real time to provide the amount of water for a given application of hydraulic fracturing. An advantage can be the flexibility to generate water for hydraulic fracturing of a hydrocarbon formation at a required or beneficial flow rate and pressure close to the required flow rate and pressure. The flow rate of the base water generated for hydraulic fracturing can be adjusted in real time to meet the needs of the hydraulic fracturing operation. In general, the process pressure can be changed over time without significantly impairing performance. In an embodiment, the process can be easily stopped and waited between hydraulic fracturing operations and restarted as needed.

[0094] In an embodiment, the method may be carried out locally at the drilling site utilizing the produced drilling grade BaSO4(s). In an embodiment, the produced BaSO4(s) precipitate is easily separated from the mixed water and used in drilling operations. The method is suitable for producing drilling grade barite (BaSO4(s)). Barite is a mineral composed of barium sulfate (BaSO4). API Standard 13A (18th Edition) defining barite for drilling purposes does not refer to a specific mineral, but to materials that meet the standard. However, in practice, this is usually the mineral barite.

[0095] In embodiments, the water mix ratio and other operations of the process may be automated utilizing a programmed control algorithm (e.g., in a control system) and a series of control valves to mix the water at a specified or optimized flow rate. Embodiments are more cost-effective and flexible compared to membrane nanofiltration of seawater for the development of PW-based fracturing fluids, including PW with high Total Dissolved Solids (TDS).

[0096] FIG. 7 is a method 700 for producing base water for hydraulic fracturing fluids and producing barium sulfate. Producing base water from PW and seawater can beneficially reduce or eliminate the use of fresh water for the base water. Additionally, a synergistic effect of the method is the simultaneous production of solid barium sulfate (second product stream), which can be drilling grade barite as a weighting agent for the drilling fluid. In an embodiment, barium is not added to the PW. In an embodiment, fresh water is not added to the PW.

[0097] In step 702, the method includes treating the PW prior to combining it with seawater. The PW may include water separated from hydrocarbons produced from a subterranean formation. Treating the PW may include de-oiling the PW, as described above. Treating the PW may include softening the PW, also as described above. Softening may include treating the PW to remove calcium and magnesium from the PW. The seawater may undergo processing such as filtration or nanofiltration to remove solids. However, nanofiltration of seawater may be beneficially avoided in practice.

[0098] In step 704, the method includes combining (e.g., mixing) the (e.g., treated) PW with seawater to obtain a mixture and allow precipitation of BaSO4(s). In an embodiment, no barium is added to the mixture other than the barium in the PW produced from the subterranean formation. In an embodiment, no fresh water is added to the mixture. The mixing of the PW and seawater can occur in a mixing vessel. The discussion herein refers to seawater in the Arabian Gulf, but seawater from other parts of the world is also applicable. Seawater typically contains sulfates.

[0099] In step 706, the method includes precipitating BaSO from the barium in the product water and sulfates in the seawater contained in the mixture. Precipitation results in a precipitate having BaSO(s). Precipitation may occur in a mixing vessel.

[0100] In step 708, the method includes separating the precipitated BaSO(s) from the mixture to obtain base water for the hydraulic fracturing fluid. The BaSO(s) precipitate can be separated from the mixture in a separation vessel, such as, for example, a decanter vessel (gravity vessel) or a filter vessel.

[0101] In step 710, the method includes producing or generating base water by separating the precipitated BaSO(s) from the mixture. Again, the base water may be base water for hydraulic fracturing fluids. The base water has a sulfate concentration below a certain maximum concentration (threshold) (e.g., 900 ppm).

[0102] In step 712, the method includes separating the precipitated BaSO4(s) from the mixture to produce BaSO4(s). The BaSO4(s) may be utilized as an additive (e.g., weight agent) for drilling fluids. The method may include draining or recovering the separated BaSO4(s) to obtain drilling grade barite as a weight agent for drilling fluids. The method may also include providing the separated precipitate to obtain BaSO4(s) as a weight agent for drilling fluids.

[0103] In step 714, the method includes specifying (or adjusting) an amount of seawater in the mixture that correlates with (or is responsive to) the amount of barium in the PW, or maintaining a sulfate concentration in the base water below a sulfate concentration threshold. Specifying (or adjusting) the amount of seawater in the mixture may be to increase the amount of barium sulfate precipitation while maintaining the sulfate concentration in the base water below a specified maximum concentration.

[0104] Specifying (or adjusting) the amount of seawater in the mixture may include specifying (or adjusting) a volume percent of seawater in the mixture, or a volume ratio of seawater to PW in the mixture. The amount of seawater in the mixture may be initially specified (e.g., based on the barium concentration in the PW and the sulfate concentration in the seawater). The amount of seawater may then be adjusted (e.g., in real time) in response to, for example, changes in the barium concentration of the PW or the sulfate concentration of the seawater, or in response to the sulfate concentration in the base water exceeding a threshold value.

[0105] As mentioned above, the maximum concentration of sulfate in the base water (and thus the fracturing fluid) that is acceptable may depend on the water chemistry of the fracturing fluid with the formation water of the subterranean formation subjected to hydraulic fracturing. For example, the higher the concentration of Ba, Ca and Sr in the formation water, the lower the concentration of sulfate in the fracturing fluid should be. Thus, the method may include identifying a maximum (threshold) sulfate concentration in the base water that is not exceeded in the formation water of the subterranean formation subjected to hydraulic fracturing with the fracturing fluid incorporating the base water, in response to the concentrations of Ba, Ca and Sr in the formation water of the subterranean formation. In other words, the method may include hydraulic fracturing with the fracturing fluid incorporating the base water, specifying a maximum or threshold concentration of sulfate in the base water that correlates (based on) the concentration of ions (e.g., cations) in the formation fluid in the subterranean formation, the ions including barium, calcium and strontium. The maximum sulfate concentration in the base water may be specified inversely proportional to the respective concentrations of barium, calcium, and strontium in the formation fluids in a subterranean formation that may be hydraulically fractured with the fracturing fluid.

[0106] Recovery of seawater and formation water (produced water or PW) to obtain the highest quality fracturing fluid base (low sulfate) may be the primary variable, and producing the maximum amount of barium sulfate may be a secondary variable. Embodiments include (1) recovering seawater and PW to obtain the highest quality fracturing fluid base, and (2) using the sediment produced by mixing seawater and PW for other applications, such as drilling.

[0107] By limiting the residual sulfate concentration, the formation of some precipitates (e.g., CaSO4 and SrSO4) can be advantageously suppressed. The ratio of PW to seawater (e.g., to provide a molar ratio of at least 1 sulfate to about 1.43 Ba) can be such that there is enough barium (from PW) present to precipitate most of the sulfate (from seawater) as BaSO4. However, the precipitation of BaSO4 and other sulfates depends on the SR of BaSO4 and other sulfates, and as a result, the molar ratio that is implemented may be greater than (e.g., greater than) 1.43 Ba to SO4.

[0108] An embodiment is a method of producing base water for hydraulic fracturing fluids and producing barium sulfate. The method includes treating produced water to remove oil from the produced water. The produced water can be water separated from hydrocarbons produced from a subterranean formation. The method includes treating the produced water to remove calcium and magnesium from the produced water. The method includes mixing the produced water with seawater to obtain a mixture and precipitating barium sulfate in the mixture from barium in the produced water and sulfates in the seawater. In an embodiment, barium is not added to the produced water, barium is not added to the seawater, and barium is not added to the mixture. In an embodiment, fresh water is not added to the mixture. The method includes separating the precipitated barium sulfate from the mixture to obtain base water for hydraulic fracturing fluids, the base water having less than a particular concentration of sulfates. The method includes collecting the separated barium sulfate to obtain barium sulfate as a weighting agent for the drilling fluid. The barium sulfate can provide drilling grade barite. The method may include adjusting a volume percent of seawater in the mixture to maintain a concentration of sulfate in the base water below a particular sulfate concentration. The method may include adjusting a volume percent of seawater in the mixture to increase the amount of barium sulfate precipitation while maintaining a concentration of sulfate in the base water below a specified concentration. The method may include specifying a volume percent of seawater in the mixture that correlates with an amount of barium in the product water.

[0109] Another embodiment is a method of producing base water for a hydraulic fracturing fluid and producing barium sulfate. The method includes combining produced water having barium with seawater to obtain a mixture, the produced water being water produced from a subterranean formation in the production of hydrocarbons from the subterranean formation. Combining the produced water with seawater may include mixing the produced water with seawater. The method includes precipitating the barium sulfate in the mixture from the barium in the produced water and the sulfates in the seawater to obtain a precipitate having barium sulfate. The method includes separating the precipitate from the mixture to obtain base water for the hydraulic fracturing fluid, the base water having less than a specified maximum concentration of sulfates. The method includes providing the separated precipitate to obtain a weight agent for the drilling fluid. The precipitate may be or include drilling grade barite. The method may include identifying a volumetric ratio of produced water to seawater in the mixture such that a concentration of sulfates in the base water is less than a specified maximum concentration. The method may include adjusting a volumetric ratio of seawater to produced water to increase the amount of barium sulfate precipitation while maintaining a concentration of sulfates in the base water less than a specified maximum concentration. The method can include identifying a volume ratio of seawater to produced water in the mixture that correlates with an amount of barium in the produced water. The method can include de-oiling the produced water. The method can include softening the produced water. The method can include specifying certain maximum concentrations that correlate with concentrations of cations in formation fluids in a subterranean formation being hydraulically fractured with a fracturing fluid that includes base water, the cations including at least barium, calcium, and strontium.

[0110] Yet another embodiment is a method of producing base water for a hydraulic fracturing fluid and producing barium sulfate. The method includes, for example, mixing produced water having barium with seawater to obtain a mixture, the produced water including water produced from a subterranean formation. The method includes precipitating barium sulfate in the mixture from the barium and sulfates in the seawater. The method includes separating the precipitated barium sulfate from the mixture to obtain base water for the hydraulic fracturing fluid, the base water being below a sulfate concentration threshold. The method includes providing separated barium sulfate to obtain drilling grade barite as a weighting agent for the drilling fluid. The method includes designating an amount of seawater combined with the produced water as a function of a barium concentration in the produced water. Designating the amount of seawater may include adjusting the amount of seawater combined with the produced water as a function of a barium concentration in the produced water. Specifying the amount of seawater may include adjusting a volume ratio of seawater to produced water in the mixture to maintain a sulfate concentration in the base water below a sulfate concentration threshold, or may include adjusting a volume percentage of seawater in the mixture to maintain a sulfate concentration in the base water below a sulfate concentration threshold. The method may include identifying a sulfate concentration threshold that correlates with a concentration of cations in formation fluids in a subterranean formation being hydraulically fractured with a fracturing fluid including the base water, where the ions include barium, calcium, and strontium. The method may include treating the seawater to remove particles from the seawater prior to mixing the seawater with the produced water. The method may include de-oiling and softening the produced water.

[0111] Although several embodiments have been described, it will be understood that various modifications may be made without departing from the spirit and scope of the disclosure.

Claims

Claim 1 A method for generating base water for a hydraulic fracturing fluid and producing barium sulfate, comprising: treating produced water to remove oil therefrom; treating the produced water to remove calcium and magnesium therefrom; combining the produced water with seawater to obtain a mixture; precipitating barium sulfate in the mixture from barium in the produced water and sulfate in the seawater; separating the precipitated barium sulfate from the mixture to obtain base water for a hydraulic fracturing fluid having a sulfate content less than a specific sulfate concentration; recovering the separated barium sulfate to obtain the barium sulfate as a weighting agent for a drilling fluid. A method. Claim 2 The produced water includes water separated from hydrocarbons produced from an underground formation, and the barium sulfate as a weighting agent comprises drilling-grade barite. The method according to claim 1. The method according to claim 1. Claim 3 Barium is not added to the produced water, not added to the seawater, and not added to the mixture. The method according to claim 2. The method according to claim 2. Claim 4 Fresh water is not added to the mixture. The method according to claim 2. The method according to claim 2. Claim 5 The method according to claim 1, further comprising adjusting a volume percentage of the seawater in the mixture to maintain a sulfate concentration in the base water below the specific sulfate concentration. The method according to claim 1. Claim 6 The method according to claim 1, further comprising adjusting a volume percentage of the seawater in the mixture to increase an amount of the precipitated barium sulfate while maintaining a sulfate concentration in the base water below the specific sulfate concentration. The method according to claim 1. Claim 7 The method according to claim 1, further comprising specifying a volume percentage of the seawater in the mixture correlated with an amount of the barium in the produced water. The method according to claim 1.

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