H 2s abatement using combined chemical and mechanical treatment with fluid and pressure control

Abstract

Method and apparatus for drilling wells and processing drilling fluids are described herein. A method of processing a drilling fluid includes reducing pH of the drilling fluid to convert dissolved sulfides to hydrogen sulfide to form a low pH fluid; removing hydrogen sulfide from the low pH drilling fluid using a mechanical treatment to form a reduced sulfide fluid; and raising the pH of the reduced sulfide fluid to form a reduced sulfide drilling fluid precursor. The drilling fluid subjected to such treatment can be reused with minimal use of fresh water.

Description

Attorney Docket No. IS24.1988-WOH2S ABATEMENT USING COMBINED CHEMICAL AND MECHANICAL TREATMENT WITH FLUID AND PRESSURE CONTROLCROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This patent application claims benefit of United States Provisional Patent Application Serial No. 63 / 735,071 , filed December 17, 2024, which is entirely incorporated herein by reference.FIELD

[0002] The subject matter herein relates to apparatus and methods for removing sulfides from fluids. Specifically, methods and apparatus herein relate to removing sulfides from fluids surfaced from subterranean locations.BACKGROUND

[0003] When a hydrocarbon well is drilled, water is circulated into the well, among other materials, to facilitate drilling. This water often returns to the surface carrying solids and sulfides, including hydrogen sulfide (H2S). The sulfides have the potential to damage equipment at the surface and in the well, so the produced water is typically not reused. Each well drilled thus consumes and disposes of approximately 40,000 barrels of water. Removing H2S from drilling fluid typically relies upon mechanical separation methods such as degassers and mud gas separators. The Pressure and Fluid Management System (PFMS) of SLB effectively removes free gas (i.e. , H2S) and solids from produced water. In most cases, however, a significant amount of H2S and other sulfides remain in solution and cannot be removed by mechanical means. There is a need for efficient and effective means of treating produced water, and other fluids, to remove sulfides so the water can be reused in well drilling.SUMMARY

[0004] Embodiments described herein provide a method of processing a fluid containing dissolved sulfides, comprising reducing pH of the fluid by treating the fluid with an acid to convert the dissolved sulfides to hydrogen sulfide to form an acidAttorney Docket No. IS24.1988-WO treated fluid; removing hydrogen sulfide from the acid treated fluid using a mechanical treatment to form a reduced gas fluid; and raising the pH of the reduced gas fluid to form reduced sulfide output fluid.

[0005] Other embodiments described herein provide a method of drilling a well, comprising capturing a drilling fluid circulated through the well in a vessel; performing a first chemical treatment on the drilling fluid by injecting an acid into the vessel to form an acid treated fluid; removing hydrogen sulfide from the acid treated fluid to form a reduced gas fluid; performing a second chemical treatment on the reduced gas fluid by injecting a base into the reduced gas fluid to form a drilling fluid precursor; removing solids from the drilling fluid precursor to form a recycle drilling fluid; and circulating the recycle drilling fluid into the well.

[0006] Other embodiments described herein provide an apparatus for removing dissolved sulfides from a fluid, the apparatus comprising a vessel configured receive the fluid; an acid source fluidly coupled to the vessel to reduce pH of the fluid; a separator fluidly coupled to the vessel to receive fluid from the vessel and separate hydrogen sulfide from the received fluid to form a reduced gas fluid; a low pressure separator fluidly coupled to the separator to receive reduced gas fluid from the separator and separate hydrogen sulfide to form a minimized gas fluid; a base source fluidly coupled to an outlet of the low pressure separator to raise the pH of the minimized gas fluid; and a sensor system configured to monitor a process performed using the apparatus.BRIEF DESCRIPTION OF THE DRAWINGS

[0007] Fig. 1 is a flow diagram summarizing a method of processing a drilling fluid according to one embodiment.

[0008] Fig. 2 is a graph showing fraction of dissolved sulfide present in aqueous solution as a function of pH.

[0009] Fig. 3 is a schematic process diagram of an apparatus that can be used to perform the method of Fig. 1 .DETAILED DESCRIPTIONAttorney Docket No. IS24.1988-WO

[0010] Drilling fluid used to facilitate drilling wells is typically maintained at high pH, for example around 10-10.5 to minimize corrosion of equipment as acidic species from the subterranean environment are liberated by the drilling operation. The high pH of the drilling fluid dissolves sulfides into bisulfide ions (SH_) and counterions, which remain in solution at elevated pH.

[0011] The methods herein use a chemical treatment to lower the pH of the drilling fluid prior to mechanical treatment to remove solids and gases. Lowering the pH of the drilling fluid to a point at which bisulfide ions recombine with hydrogen ions to form H2S, such as below about 6, for example a pH range of about 4 to about 5, can remove dissolved sulfides almost completely, usually at least by 90%, enabling removal of the great majority of sulfides using a conventional mechanical treatment, for example with a mud gas scrubber. After removal of H2S, pH of the fluid is again increased to a level suitable for use in downhole equipment by a second chemical treatment using a basic material. The fluid can then be further processed as usual to prepare for reuse.

[0012] The chemical treatment to reduce pH can use any acid capable of reducing the pH of the drilling fluid by a suitable amount. Mineral and / or organic acids can be used. Examples include hydrochloric acid (HCI), sulfuric acid (H2SO4), formic acid (H2CO2), and acetic acid (C2O2H4) can all be used, among others. Combinations of such acids can be used. The second chemical treatment can be performed using basic materials such as alkali metal hydroxides such as sodium or potassium hydroxide, alkaline earth metal oxides and hydroxides such as calcium and magnesium oxides and hydroxides, and organic bases such as amines (e.g., alkyl amines or alkanolamines such as monoethanolamine), amides, pyridines, imidazoles, and ammonium hydroxide. Combinations of such basic materials can be used.

[0013] Treatment with the basic material neutralizes acidic species in the drilling fluid, leaving neutralization products such as salts. Because the drilling fluid is to be reused after the second chemical treatment, where the salts have any unwanted effect they can be removed prior to reuse of the drilling fluid, for example by precipitation, washing, or extraction. Where HCI and NaOH are used, respectively,Attorney Docket No. IS24.1988-WO for the first and second chemical treatment, the neutralization product is NaCI, which is generally tolerated both environmentally and by production equipment to high concentrations. As salts accumulate in recirculated drilling fluid from sulfide removal treatment, any marginal effects on density and viscosity can be addressed using suitable fluids for such purposes. In some cases, water can be added to reduce density and viscosity of the drilling fluid.

[0014] Fig. 1 is a flow diagram summarizing a method 100 of processing a drilling fluid. A drilling fluid is an example of a fluid that can be treated using the methods herein. Generally, any fluid having dissolved sulfides to be removed can be processed using methods, including the method 100, and apparatus herein to remove the sulfides. At 102, the drilling fluid is collected in a vessel, such as a skimmer tank, to receive a first chemical treatment. The tank can have a longitudinal axis that is vertical or horizontal, or any suitable angle between. The fluid can be collected and held in a tank, such as a skimmer tank, or the fluid can be collected into a pipe to flow during treatment. Thus, the fluid can be in a static state or in a flowing state for treatment.

[0015] At 104, a first chemical treatment is performed on the fluid, in which an acid is added to the fluid in the vessel to reduce the pH of the fluid to 5.0 or below. Any suitable acid can be used in any suitable concentration. In one version, a 5% (by mass) HCI solution is injected into the fluid to lower pH to 5 or below. The acid can be injected into the fluid while the fluid is held in a tank or while the fluid flows along a pipe.

[0016] At pH of 5 or lower, sulfide ions in solution form hydrogen sulfide within the fluid. Fig. 2 is a graph showing fraction of dissolved sulfides present in aqueous solution as a function of pH. The graph shows that below a pH of about 6, unless otherwise treated, essentially all sulfide becomes H2S, so virtually no sulfide remains dissolved in the aqueous medium. At higher pH, frequently found in fluids such as drilling fluid used in oil and gas processing to protect equipment from corrosion, the graph shows substantial dissociation and dissolution of sulfides in the aqueous medium rendering the sulfides unremovable by conventional means. H2S is generally a volatile gas that can be easily removed from a fluid mixture by heating, reducingAttorney Docket No. IS24.1988-WO pressure, and / or agitating the fluid. The H2S separates into a vapor phase that can be evacuated to an appropriate disposition.

[0017] The fluid is mixed before, during, and / or after adding the acid. Where the fluid is disposed in a tank for addition of the acid, an agitator can mix the fluid with the acid in the tank. Alternately, or additionally, the fluid can be pumped through a recirculation line from a first location of the tank to a second location of the tank. Sonic energy can also be applied to mix the fluid. In some cases, mixing is started before addition of acid is started. In other cases, addition of acid is started before mixing is started. In some cases, mixing is discontinued after acid addition is discontinued, while in other cases mixing is discontinued before acid addition is discontinued. Where the acid is added to the fluid in a pipe, mixing may be accomplished by adding the acid using a jet injector that flows the acid into the fluid at a high velocity. Alternately, or additionally, a mixing unit may be disposed in and / or around the pipe to mix the acid with the fluid. The mixing unit may be passive, such as a static mixer or orifice, or the mixing unit may be active, such as an in-line agitator or a sonic applicator disposed outside and / or around the pipe. Combinations of mixing unit types can be used. Where mixing is performed in a pipe with flowing fluid, a portion of the fluid can be recycled or recirculated from a location of the pipe downstream of the mixing unit to a location of the pipe upstream of the mixing unit. Any suitable mixing method can be used.

[0018] In such methods, pH can be monitored using suitable pH sensors coupled to the vessel at a suitable location. One or more pH sensors can be coupled to the vessel. For example, where a tank is used for adding the acid a pH sensor can be coupled through a side wall of the tank. Alternately, or additionally, where mixing is performed by pumping the fluid around the tank, a pH sensor can be coupled to the pumparound line, for example in the pump suction or pump discharge. Acid addition can be adjusted based on readings from the pH sensor. The pH sensor may be disposed to sample the fluid prior to acid addition, after acid is well-mixed with the fluid, or both.

[0019] The acid can be added to the fluid in stages. For example, a first portion of the acid can be added to the fluid at a first time, and after a wait time, a secondAttorney Docket No. IS24.1988-WO portion of the acid can be added to the fluid at a second time. The acid can be added in any suitable number of stages. Adding the acid in stages can be helpful where vigorous reactions might take place, or localized areas of very low pH might harm equipment, if the entire amount of the acid is added in a short time. Where a pipe is used for mixing, acid addition can be continuous, and a flow rate of the acid addition can be set based on a flow rate of the fluid to be treated through the pipe. For staged addition using continuous fluid flow in a pipe, a first portion of the acid can be flowed continuously into the fluid within the pipe at a first location of the pipe and a second portion of the acid can be flowed continuously into the fluid within the pipe at a second location of the pipe.

[0020] The vessel can include a tank and a pipe inlet to the tank. In such cases, the acid can be added to the tank and / or to the pipe inlet to the tank. Also, in such cases, mixing can be performed within the pipe, within the tank, or both. Dispersing the acid in the fluid initially in a small space, such as the pipe inlet to the tank, can minimize equipment that might be exposed to concentrated acid, potentially minimizing investment in equipment. In some cases, acid addition can be at the inlet pipe and also at the tank. Where the fluid is provided to a tank in continuous flow for acid mixing, a first portion of the acid can be continuously provided at the inlet pipe and a second portion of the acid can be continuously provided into the tank.

[0021] After injection of the acid, the contents of the vessel are then routed as an acid treated fluid to a first separator at 106, which removes free gas from the acid treated fluid. As a result of lowering the pH to a suitable level, at 108 dissolved sulfides are almost completely converted to hydrogen sulfide and removed from the acid treated fluid by phase separation in the first separator, which can be a mud-gas separator, to form a reduced gas fluid. The free gases can be vented appropriately, for example to a flare stack if available. If the first chemical treatment is performed by injecting acid solution into a flowing fluid, for example into a pipe or other conduit, the first chemical treatment could be performed directly in, or immediately adjacent to, the first separator, for example by injecting the acid solution into an inlet pipe of the first separator.Attorney Docket No. IS24.1988-WO

[0022] The first separator can be a tank or pipe that positions the fluid to allow the free gas to separate into a head space. A tank sized to provide a head space above a suitable quantity of the fluid can be used. Alternately, or additionally, a vertical section of pipe having sufficient length and width for residence time can also be used. For example, a vertical section of pipe that has a top bend to a lateral section of pipe, which may be horizontal, can separate free gas, which can be vented at an upper part of the lateral section. The head space can be vented under process pressure by providing a fluid path for the free gas to a suitable disposition, such as a flare or sulfuric acid unit.

[0023] Alternately, or additionally, a sweep gas, such as nitrogen, air, or other convenient gas, can be provided to the head space of the first separator to carry free gas from the first separator to a disposition. Where the free gas is to be routed to a flare, air can be used as a sweep gas in sufficient quantity to provide a combustible mixture to the flare. To avoid producing a combustible mixture within the first separator, a quantity of air that is less than needed to form a combustible mixture can be used as sweep gas to remove the free gas from the first separator, and a second quantity of air can be added to the gas mixture as the gas mixture approaches the flare to form a combustible mixture at the flare.

[0024] Alternately, or additionally, the sweep gas can be provided to the first separator at a location that is within the liquid portion of the contents of the first gas separator. In such cases, the sweep gas can be caused to percolate through the acid treated fluid to enhance phase separation of H2S from the acid treated fluid. In some cases, the sweep gas can be provided at the bottom of a column of the acid treated fluid to percolate the entire length of the fluid column to the head space. A sparger can optionally be used to distribute the sweep gas across the width of the column of fluid. Flowing the sweep gas through the fluid in the first separator can be performed along with operation of a mixing unit within the first separator, such that the mixing unit mixes the acid treated fluid along with the sweep gas percolating through the acid treated fluid, applying shear to increase phase boundary surface area to increase transport of H2S from the acid treated fluid to the gas phase. TheAttorney Docket No. IS24.1988-WO percolating sweep gas disengages from the acid treated fluid at the head space and separates into a vapor phase for removal.

[0025] At 109, residual gas can optionally be removed from the reduced gas fluid in a second separator, which can be the same as the first separator or different from the first separator. It is expected that the amount of gas that would be removed in the second separator is different from the amount removed in the first separator, so different mixing and / or sweep gas methods might be used in the two separators. The second separator might be smaller than the first separator to process reduced gas volumes. Alternately, or additionally, the second separator may use more intensive mixing methods and / or more sweep gas than the first separator to remove as much H2S as possible in the second separator. The second separator may be operated at a lower pressure than the first separator to facilitate residual gas removal.

[0026] The reduced gas fluid effluent from the first separator, or optionally from the second separator, is routed to a vacuum vessel at 110. At 112, pressure is lowered in the environment of the reduced gas fluid to a sub-atmospheric level to facilitate further removal of entrained gas from the reduced gas fluid to form a minimized gas fluid that exits the third separator 350 through a fluid effluent 382 (FIG. 3). Mixing may be performed in the vacuum vessel as well. The vacuum vessel may be a tank, a pipe, or a combination thereof. Pressure in the vacuum vessel may be controlled by providing a gas pad above the liquid contents of the vacuum vessel. The gas pad may be the same as the sweep gas used for the first, and optional second, separator, or a different gas can be used. Gas removed from the reduced gas fluid in the vacuum vessel can be combined with gas removed in the first, and optional second, separator for routing to a subsequent use or disposition. After vacuum treatment, the minimized gas fluid may have remaining dissolved sulfides at a level of 3 ppm or less.

[0027] The minimized gas fluid is subjected to a second chemical treatment at 114 to adjust the pH of the minimized gas fluid to yield an output fluid that has a higher pH target suitable for subsequent operations. In the case of drilling fluids, the pH is adjusted to about 8.0, which is a normal level for drilling fluids to avoid exposing equipment to corrosive substances. A base material is added to the minimized gasAttorney Docket No. IS24.1988-WO fluid to raise the pH to the target. The output fluid, with adjusted pH, can thus be used as a drilling fluid precursor. Solids may be removed from the output fluid, using filters, desilters, centrifuges, shakers, and the like, to prepare the output fluid for reuse as a drilling fluid precursor.

[0028] The base material can be injected into the minimized gas fluid flowing at an outlet of the vacuum vessel in a way that promotes mixing, for example jet mixing. Alternately, or additionally, mixing can be applied to the material flowing at the outlet of the vacuum vessel. The location of mixing can be upstream or downstream of the location of base addition. Mixing can also be applied substantially at the location where base is added. Thus, mixing of the fluid can begin before base is added, after base is added, or substantially at the same time base is added to the fluid. The mixing can use a static or energized mixing unit, or any combination thereof, disposed at, or adjacent to, the outlet of the vacuum vessel.

[0029] The acid and base reagents used in the method 100 are used in example modes and concentrations. One acid reagent that can be used is 5% HCI in water by mass, but any suitable concentration of acid can be used, and the solution can contain other components that are not inconsistent with the purpose of the solution. One base reagent that can be used is 20% NaOH in water, but other concentrations can likewise be used. Other modes of delivering acid and base can also be used. For example, acid and / or base could be delivered as gases and / or solids in some cases.

[0030] Fig. 3 is a schematic process diagram of an apparatus 300 that can be used to perform the method 100. The apparatus 300 includes a vessel 302, which has an inlet 304 used to introduce a fluid to the vessel 302 for treatment. An acid source 306 provides acid to mix with the fluid within the vessel 302. The vessel 302 is a tank-type vessel that holds an inventory of the fluid. In this case, the contents of the vessel 302 are mixed using a pumparound 308. The acid source 306 is fluidly coupled with the pumparound 308 to add acid in the pumparound 308. The pumparound 308 has a pump 310 that moves fluid through the pumparound 308. Here, the acid source 306 is coupled to the suction side of the pump 310 to allow for introduction of the acid at a low pressure location and to use the pumping action ofAttorney Docket No. IS24.1988-WO the pump 310 for high-shear mixing. Alternately, the acid source 306 could be coupled to the pumparound 308 on the discharge side of the pump 310, which requires providing the acid at higher pressure but reduces the possibility of exposing the pump 310 to concentrated acid. Alternately or additionally, as described above, acid can be added directly to the vessel 302, at the inlet line thereof or into the large liquid volume held in the vessel 302.

[0031] In addition to mixing by action of the pump, the pumparound 308 has an optional in-line mixer 312 disposed in the pump discharge. The in-line mixer 312 can be static or energized using any suitable mixing device. For example, the mixer 312 can be, or can include, an in-line motorized mixer with an impeller disposed within the pumparound 308. In another example, the mixer 312 can be, or can include, a sonicator disposed to emit acoustic waves into the fluid flowing within the pumparound 308. Combinations of types of mixers can also be used in the in-line mixer 312. Further mixing action can be accomplished by delivering the mixed fluid from the pump back into the vessel 302 using a small flow path to form a jet. High shear from the jet of fluid entering the vessel 302 will further mix the fluids. Alternately, or additionally, as described above, a mixing unit can be disposed within the vessel 302.

[0032] A feed sensor unit 314 can be coupled with the inlet 304 to sense a condition of the fluid within the inlet 304. The feed sensor unit 314 can be, or can include, a pH sensor to determine pH of the fluid. Signals from the pH sensor of the feed sensor unit 314 can be used to determine an amount of acid from the acid source 306 to mix with the fluid flow in the inlet 304 to convert dissolved sulfides in the fluid into H2S. The amount can be a flow rate of acid from the acid source 306 or another amount that can be used to target a flow rate of the acid. The feed sensor unit 314 can contain any suitable sensors, such as temperature, pressure, and / or composition sensors for sensing various conditions of the fluid within the inlet 304.

[0033] An acid treated fluid conduit 316 couples the vessel 302 to a first separator 318 to carry acid treated fluid from the vessel 302 to the first separator 318. The first separator 318 separates free gas containing H2S from the fluid entering from the acid treated fluid conduit 316. The acid treated fluid conduit 316 is coupled to an inlet 320Attorney Docket No. IS24.1988-WO of the first separator 318, here located at, or near, a top 322 of the first separator 318. Within the first separator 318, free gas is separated from the fluid entering from the acid treated fluid conduit 316 into a vapor space within the first separator 318 to yield a reduced gas fluid which is withdrawn from the first separator 318 at an outlet 326 thereof into an acid treated fluid conduit 324. Here, the outlet 326 is located at, or near, a bottom 328 of the first separator 318. Positioning of the inlet 320 and the outlet 326, in this case, results in a downward flow of the acid treated fluid within the first separator 318 while gas is released from the fluid and rises through the fluid column to accumulate in the vapor space near the top 322.

[0034] A gas source 330 provides a sweep gas to a gas inlet 331 of the first separator 318 at the bottom 328 thereof. A sparger 332 is used, in this case, with the sweep gas provided between the sparger 332 and the bottom 328 of the first separator 318, As noted above, use of a sweep gas is optional. The gas may be an inert gas, such as nitrogen, or a functional gas such as air or another oxygencontaining gas. For example, if the removed gas is to be routed to a flare, using air as the gas facilitates such disposition Using a sparger 332 evenly distributes the sweep gas to percolate through the acid treated fluid within the first separator 318, improving removal of free gas. The free gas containing H2S is removed from the first separator 318 at a gas outlet 334 located at the top 322 of the first separator 318.

[0035] The first separator 318 outputs a reduced gas fluid, which is routed to a second separator 336 using a reduced gas fluid conduit 324. As noted above, use of the second separator is optional. Here, the second separator 336 is substantially the same as the first separator 318, but in other cases the second separator 336 can be different from the first separator 318 in any suitable manner. The same downward flow pattern is created in the second separator 336, and sweep gas is provided using a sparger 338, which is a second sparger where the sparger 332 is a first sparger, each of which is optional. The gas source 330 is coupled to both the first and second separators 318 and 336 in this case, but in other cases a second gas source, different from the gas source 330, can provide sweep gas to the second separator 336. Thus, each separator 318 and 336 can have its own independent sweep gas source. Alternately, the second separator 336 can operate with no sweep gas. As with theAttorney Docket No. IS24.1988-WO first separator 318, the sweep gas from the gas source 330 is coupled to a gas inlet 346, which in this case is a second gas inlet where the gas inlet 331 is a first gas inlet. As with the first separator 318, the gas inlet 346 is at a bottom 348 of the second separator 336. In each of the first and second gas separators 318 and 336, sweep gas percolates upward through a descending column of fluid to remove gas from the fluid. Residual gas removed in the second separator 336 is withdrawn at a second gas outlet 340, which is at a top 342 of the second separator 336, and a second reduced gas fluid is withdrawn from the second separator 336 using a second reduced gas fluid conduit 344 coupled near the bottom 348 of the second separator 336, similar to the first separator 318.

[0036] Flow controllers can be used to control flow of sweep gas to the first separator 318, and to the optional second separator 336. A first flow controller 352 can be disposed in a first sweep gas line 354 that couples the sweep gas source 330 with the first separator 318. A second flow controller 356 can be disposed in a second sweep gas line 358 that couples the sweep gas source 330 with the second separator 336. The two flow controllers 352 and 356 can be adjusted to set a flow rate of sweep gas to the separators 318 and 336 based on flow rate of reduced gas fluid to the separators and / or based on quantity of sulfides to be removed and / or based on a desired composition of the effluent gas from the separators 318 and 336. The flow controllers 352 and 356 can also be operated interdependently. For example, a flow rate of the second flow controller 356 can be set based on a flow rate setting, or an actual flow rate, of the first flow controller 352.

[0037] The second reduced gas fluid conduit 344 routes the second reduced gas fluid to a third separator 350, which is a low pressure separator, for example a vacuum separator, that operates at a lower pressure than the first and second separators 318 and 336. Gas removed from the fluid in the third separator 350 is removed at a gas outlet 360 at an upper location of the third separator 350. The gases removed from the first, optional second, and third separators 318, 336, and 350 can be combined in a common gas header 362 for common disposition, for example for routing to a flare.Attorney Docket No. IS24.1988-WO

[0038] An acid treated fluid sensor unit 364 can be coupled to the acid treated fluid conduit 316 to sense a condition of the acid treated fluid in the conduit 316. Like the feed sensor unit 314, the acid treated fluid sensor unit 364 can be, or can include, a pH sensor. Signals from the pH sensor can be used to determine pH of the acid treated fluid and / or to compare to a target to ensure a pH of the acid treated fluid reaches a target, such as below 6.0 or below 5.0. Input of acid from the acid source 306 can be adjusted, based on signals from the acid treated fluid sensor unit 364, to raise or lower pH of the acid treated fluid. Like the feed sensor unit 314, the acid treated fluid sensor unit 364 can also include other suitable sensors, such as temperature, pressure, and / or composition sensors, to sense various conditions of the acid treated fluid. The sensors 364 and 314 can also be used to monitor material balance of the fluid input to, and output from, the vessel 302. Signals from the fluid sensor unit 364 can also be used to infer a quantity of gas expected to separate in the first separator 318.

[0039] Reduced gas fluid sensor units can be coupled to the conduits 324 and 344 as well. A first reduced gas fluid sensor unit 366 can be coupled to the first reduced gas fluid conduit 324. A second reduced gas fluid sensor unit 368 can be coupled to the second reduced gas fluid conduit 344. These sensors, which can be, or can include pH sensors, along with other suitable sensors such as temperature, pressure, and composition sensors, can be used to sense various conditions of the reduced gas fluids in the conduits 324 and 344. Signals from a pH sensor coupled to the first reduced gas fluid conduit 324 can be used to infer pH of the first reduced gas fluid. The signals from the first reduced gas fluid sensor unit 366 can be compared with signals from the acid treated fluid sensor unit 364 to determine a change in condition occurring in the first separator 318. For example, a change in pH detected using the acid treated fluid sensor unit 364 and the reduced gas fluid sensor unit 366 can indicate a volume of sulfur-containing gas removed from the acid treated fluid in the first separator 318. Likewise, a change in pH detected using the two reduced gas fluid sensor units 366 and 368 can indicate a volume of sulfur- containing gas as removed in the second separator 336. Where convenient, the sensor units 366 and 368 may include spectral sensors, such as IR sensors or UV sensors, that can detect lower levels of sulfides in the fluids.Attorney Docket No. IS24.1988-WO

[0040] A gas analyzer can be coupled to one or more of the gas effluent conduits from the various separators. A gas analyzer 370, which may be a first gas analyzer if other gas analyzers are used, may be coupled with a first gas effluent 372 of the first separator 318. A gas analyzer 374, which may be a second gas analyzer if other gas analyzers are used, may be coupled with a second gas effluent 376 of the second separator 336. A gas analyzer 378, which may be a second or third gas analyzer if other gas analyzers are used, may be coupled with a third gas effluent 380 of the third separator 350. Each of the gas analyzers 370, 374, and 378 may be a spectral analyzer, a chromatographic analyzer, or a combination thereof. The gas analyzers 370, 374, and 378 can output signals representing a composition of the gas flowing in each respective effluent. From such signals, a quantity of H2S in the analyzed gas can be inferred and used to control operation of the respective separator or other units of the apparatus 300.

[0041] A sensor system that includes pH sensors and optionally gas analyzers, as described above, also optionally including temperature, pressure, and flow sensors, can be used to control the sulfide removal process using the apparatus 300. The pH analyzers can be used to determine a quantity of acid needed to lower the pH of the feed fluid to less than 6.0, or less than 5.0, and can be used to monitor the pH of the acid treated fluid to ensure the dissolved sulfides are converted in the various separators. The pH sensors can be used to monitor quantity of sulfide removed in the various separators, and the gas analyzers can confirm how much sulfide is removed. Flow sensors can provide information on total mass flow and mass flow of sulfides, particularly coupled with the pH sensors and gas analyzers. Temperature sensors can provide information on temperature, from which sulfide removal rates, as a function of temperature, can be inferred.

[0042] The methods described herein can thus be used to remove dissolved sulfides from any high pH aqueous fluid. In general, fluids in process industries might be maintained at high pH to avoid or minimize corrosion of equipment. Where such fluids have, or acquire, significant concentration of sulfides, the sulfides can be removed using the methods herein. For example, where water at elevated or high pH contacts any material having sulfides that can dissolve in water having elevatedAttorney Docket No. IS24.1988-WO pH, the water carrying the sulfides can be treated as described herein. In one example, water may be contacted with an organic stream, such as a hydrocarbon or crude oil stream, and mixed vigorously to allow sulfides to transport, at least partially, from the organic stream into the water, thus lowering the sulfides content of the organic stream. The water, now bearing sulfides, can then be treated using the methods and apparatus described herein.

[0043] The preceding description has been presented with reference to present embodiments. In particular, the methods described herein are rooted in the context of hydrocarbon prospecting. Persons skilled in the art and technology to which this disclosure pertains will appreciate that alterations and changes in the described structures and methods of operation can be practiced without meaningfully departing from the principle, and scope of this present disclosure. For example, the methods described herein are applicable to any water produced from a subterranean location. These methods can, therefore, find use in other oil and gas settings for treatment of produced waters prior to reinjection of those waters. These methods can also be used to treat wastewater for various industries, such as mining, chemicals manufacturing, and the pulp and paper industries. Accordingly, the foregoing description should not be read as pertaining only to the precise structures described and shown in the accompanying drawings, but rather should be read as consistent with and as support for the following claims, which are to have their fullest and fairest scope.

Claims

Attorney Docket No. IS24.1988-WOClaims1 . A method of processing a fluid containing dissolved sulfides, comprising: reducing pH of the fluid by treating the fluid with an acid to convert the dissolved sulfides to hydrogen sulfide to form an acid treated fluid; removing hydrogen sulfide from the acid treated fluid using a mechanical treatment to form a reduced gas fluid; and raising the pH of the reduced gas fluid by treating the reduced gas fluid with a base to form a reduced sulfide output fluid.

2. The method of claim 1 , wherein the fluid is a drilling fluid and the output fluid is a drilling fluid precursor.

3. The method of claim 1 , wherein the mechanical treatment comprises flowing a gas through the acid treated fluid.

4. The method of claim 1 , wherein the mechanical treatment comprises reducing a pressure of the acid treated fluid.

5. The method of claim 3 or 4, wherein the mechanical treatment further comprises mixing the acid treated fluid.

6. The method of claim 5, wherein the mixing comprises disposing the acid treated fluid in a vessel and flowing the acid treated fluid through a pumparound coupled with the vessel.

7. The method of claim 1 , wherein the mechanical treatment uses: a separator, wherein the acid treated fluid is mixed, free gas is collected in a vapor space, and the free gas is withdrawn to form a reduced gas fluid; and a low pressure separator, wherein the reduced gas fluid is subjected to a reduced pressure, additional gas is collected in a vapor space, and the additional gas is withdrawn to form a minimized gas fluid.Attorney Docket No. IS24.1988-WO8. The method of claim 1 , wherein the acid is selected from the group consisting of hydrochloric acid, sulfuric acid, formic acid, acetic acid, and combinations thereof.

9. The method of claim 1 , wherein the base is selected from the group consisting of alkali metal hydroxides, alkaline earth metal oxides, alkaline earth metal hydroxides, amines, amides, pyridines, imidazoles, ammonium hydroxide, and combinations thereof.

10. A method of drilling a well, comprising: capturing a drilling fluid circulated through the well in a vessel; performing a first chemical treatment on the drilling fluid by injecting an acid into the vessel to form an acid treated fluid; removing hydrogen sulfide from the acid treated fluid to form a reduced gas fluid; performing a second chemical treatment on the reduced gas fluid by injecting a base into the reduced gas fluid to form a drilling fluid precursor; removing solids from the drilling fluid precursor to form a recycle drilling fluid; and circulating the recycle drilling fluid into the well.

11. The method of claim 10, wherein removing hydrogen sulfide from the acid treated fluid comprises passing the treated fluid to a separator to collect free gas from the acid treated fluid in a vapor space.

12. The method of claim 10, wherein removing hydrogen sulfide from the acid treated fluid comprises flowing a sweep gas through the acid treated fluid.

13. The method of claim 10, further comprising monitoring pH of the acid treated fluid using a pH sensor and adjusting the injection of acid based on signals from the pH sensor.

14. The method of claim 10, wherein removing solids from the drilling fluid precursor comprises passing the drilling fluid precursor through at least one of a shaker, a desilter, or a centrifuge.Attorney Docket No. IS24.1988-WO15. The method of claim 10, further comprising analyzing composition of gas removed from the acid treated fluid using a gas analyzer.

16. The method of claim 10, wherein the first chemical treatment comprises injecting a first portion of the acid at a first time and a second portion of the acid at a second time after a wait time.

17. The method of claim 10, further comprising subjecting the acid treated fluid to a reduced pressure in a vacuum separator to remove additional hydrogen sulfide before performing the second chemical treatment.

18. An apparatus for removing dissolved sulfides from a fluid, the apparatus comprising: a vessel configured to receive the fluid; an acid source fluidly coupled to the vessel to reduce pH of the fluid; a separator fluidly coupled to the vessel to receive fluid from the vessel and separate hydrogen sulfide from the received fluid to form a reduced gas fluid; a low pressure separator fluidly coupled to the separator to receive reduced gas fluid from the separator and separate hydrogen sulfide to form a minimized gas fluid; a base source fluidly coupled to an outlet of the low pressure separator to raise the pH of the minimized gas fluid; and a sensor system configured to monitor a process performed using the apparatus.

19. The apparatus of claim 18, wherein the separator is a first separator and further comprising a second separator fluidly coupled between the first separator and the low pressure separator to receive reduced gas fluid from the first separator and output a second reduced gas fluid to the low pressure separator.

20. The apparatus of claim 18, wherein the sensor system comprises a pH sensor coupled to the vessel.

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