Systems and methods for wellbore drilling using thermochemical sulfate reduction (TSR) metrics

Abstract

The invention relates to a system for wellbore drilling and a method for preparing wellbore drilling fluid. The system may include a drilling fluid tank containing wellbore drilling fluid for introduction into a wellbore, an additive dispensing assembly fluidly coupled with the drilling fluid tank containing a first additive, and a computing device communicatively coupled with the additive dispensing assembly. The method may include causing a computing device to perform at least the following: receive drilling parameters identifying wellbore drilling conditions of a wellbore drilling system, calculate a thermochemical sulfate reduction (TSR) index value for the wellbore. In response to determining that the predicted hydrogen sulfide concentration satisfies the predetermined threshold, the computing device may determine a first amount of a first additive to be added to the wellbore drilling fluid and combine the first amount of the first additive with the wellbore drilling fluid.

Description

Technical Field

[0001] Embodiments described herein generally relate to systems and methods for drilling a wellbore using a thermochemical sulfate reduction (TSR) proxy, and more particularly, to embodiments for utilizing a TSR proxy to modify a drilling fluid used for hydrocarbon extraction in a wellbore. Background Art

[0002] Extracting hydrocarbons from underground formations may require drilling from the surface to underground formations containing hydrocarbons through a wellbore or wellbore. Thermochemical sulfate reduction (TSR) is a process that occurs naturally within a wellbore, in which crystalline anhydrite (CaSO4) reacts with hydrocarbons at high temperatures to produce high concentrations of hydrogen sulfide (H2S) in carbonate reservoirs. TSR can destroy in situ hydrocarbon resources because the reaction produces hydrogen sulfide. In addition, the TSR process may cause corrosion and scaling of wellbores and production facilities. Hydrogen sulfide is also toxic and poses serious safety and environmental concerns to upstream operations in the petroleum industry. Therefore, when drilling conditions are unfavorable or inoperable, the TSR process may increase the cost of hydrocarbon extraction through increased maintenance and mitigation of these effects in the wellbore, as well as increased downtime to relocate the drilling system to an alternative area. Therefore, there is a need in the art for systems and methods for wellbore drilling that can reduce the risk of drilling operations in wellbores containing hydrogen sulfide. Summary of the invention

[0003] Some embodiments of using a TSR indicator for wellbore drilling may include a wellbore drilling system comprising a drilling fluid tank containing a wellbore drilling fluid for introduction into a wellbore, an additive dispensing assembly fluidically coupled to the drilling fluid tank containing a first additive, and a computing device communicatively coupled to the additive dispensing assembly. The computing device includes a processor and a memory component, the memory component storing logic that, when executed by the processor, causes the wellbore drilling system to at least perform the following operations: receive drilling parameters identifying a wellbore drilling condition of the wellbore drilling system; calculate a thermochemical sulfate reduction (TSR) indicator value for the wellbore, wherein the TSR indicator value predicts the progression of a TSR reaction in the wellbore, and wherein the TSR indicator value predicts a concentration of hydrogen sulfide in the wellbore; and determine whether the predicted concentration of hydrogen sulfide meets a first threshold. In response to determining that the predicted hydrogen sulfide concentration meets the first threshold, the wellbore drilling system may: determine a first amount of a first additive to be added to the drilling fluid tank to increase the concentration of the first additive in the wellbore drilling fluid, and send instructions to the additive dispensing assembly to release the first amount of the first additive into the drilling fluid tank.

[0004] Other embodiments include a method of preparing a wellbore drilling fluid, the method comprising causing a computing device to at least perform the following operations: receiving a drilling parameter identifying a wellbore drilling condition of a wellbore drilling system; calculating a thermochemical sulfate reduction (TSR) indicator value for the wellbore, wherein the TSR indicator value predicts the progression of a TSR reaction in the wellbore and the TSR indicator value predicts a concentration of hydrogen sulfide in the wellbore; in response to determining that the predicted hydrogen sulfide concentration meets a predetermined threshold: determining a first amount of a first additive to be added to the wellbore drilling fluid; and combining the first amount of the first additive with the wellbore drilling fluid.

[0005] Additional features and advantages of the described embodiments will be set forth in the following detailed description, and in part will be readily apparent to those skilled in the art from that description or learned by practicing the described embodiments, including the following detailed description and the claims.

[0006] BRIEF DESCRIPTION OF THE DRAWINGS

[0007] The embodiments illustrated in the drawings are illustrative and exemplary in nature and are not intended to limit the subject matter defined by the claims. The following detailed description of the illustrative embodiments may be understood when read in conjunction with the following drawings, in which like structures are represented by like reference numerals, and in which:

[0008] Figure 1 depicts a wellbore drilling system according to one or more embodiments shown and described herein;

[0009] Figure 2 Depicting additive dispensing assemblies and other components of a wellbore drilling system according to one or more embodiments shown and described herein;

[0010] Figure 3 A computing device of a wellbore drilling system is depicted according to one or more embodiments shown and described herein.

[0011] Figure 4 Depicted is a process flow diagram according to one or more implementations shown and described herein.

[0012] Figure 5 Depicted is a process flow diagram for calculating a TSR indicator value according to one or more embodiments shown and described herein. DETAILED DESCRIPTION

[0013] Embodiments of the present disclosure relate to systems and methods for drilling a wellbore using a TSR indicator. During the drilling of a wellbore, hydrogen sulfide may be encountered. Embodiments disclosed herein may predict the concentration of hydrogen sulfide in the wellbore, adjust the concentration of additives in the wellbore drilling fluid to mitigate some of the effects of increased hydrogen sulfide, and monitor both the concentration of hydrogen sulfide in the wellbore and the concentration of additives in the wellbore drilling fluid in real time. In embodiments, the wellbore drilling fluid may be further adjusted to accommodate changes in the concentration of hydrogen sulfide in the wellbore and the concentration of additives in the wellbore drilling fluid. In embodiments, a computing device may perform these calculations, monitoring, and system changes in a single automated system. Embodiments disclosed herein may reduce the risk of drilling operations when hydrogen sulfide is encountered.

[0014] As used throughout this disclosure, the terms “downhole” and “uphole” may refer to a location within a wellbore relative to the earth’s surface, with uphole meaning a direction or location closer to the earth’s surface and downhole meaning a direction or location further from the earth’s surface.

[0015] As used herein, a "subsurface formation" may refer to a rock mass that is sufficiently distinct and continuous from the surrounding rock mass that it may be mapped as a distinct entity. Thus, the subsurface formation is sufficiently homogeneous to form a single identifiable unit that contains similar properties throughout the subsurface formation, including, but not limited to, porosity and permeability.

[0016] As used throughout this disclosure, "wellbore" may refer to a borehole or wellbore extending from the surface of the earth downward to a subterranean formation, including an open hole or an uncased portion. The wellbore may form a path that allows fluids to pass between the surface and the subterranean formation. The wellbore may include at least a portion of a fluid conduit connecting the interior of the wellbore to the surface. The fluid conduit connecting the interior of the wellbore to the surface may allow regulated fluids to flow from the interior of the wellbore to the ground, and may allow access between equipment on the surface and the interior of the wellbore.

[0017] "Wellbore wall" may refer to the interface at which fluids may transition between a subterranean formation and the interior of a wellbore. The wellbore wall may be unlined (i.e., bare rock or formation) to allow such interaction with the subterranean formation, or lined (e.g., by a tubular string) to prevent such interaction. The wellbore wall may also define the void volume of the wellbore.

[0018] As used throughout this disclosure, "thermochemical sulfate reduction" (TSR) may refer to the reduction of sulfate in the presence of petroleum and heat. TSR may produce a variety of reaction products, including reduced forms of sulfur (S and H2S), calcite, and CO2, as well as a combination of water, sulfides, organosulfur compounds, and bitumen, but at the expense of hydrocarbon alteration.

[0019] Now referring to the accompanying drawings, Figure 1 A wellbore drilling system 100 is depicted according to one or more embodiments shown and described herein. The wellbore drilling system 100 can be used to form a vertical, deviated, or horizontal wellbore. The wellbore drilling system 100 includes a drilling rig 112 supported by a drilling derrick 112a. The drilling derrick 112a selectively positions a drill string 112b in a wellbore 111. The drill string 112b has a downhole end connected to a drill bit 112c, which extends the wellbore 111 in a geological formation 113. During the wellbore drilling operation, a wellbore drilling fluid (also referred to as drilling mud or mud) is circulated through the wellbore 111 drilled by the drill bit 112c.

[0020] For example, the drilling fluid tank 108 contains wellbore drilling fluid. A well pump 110 is fluidly connected to the drilling fluid tank 108 via 103a. A drilling rig 112 is fluidly connected to the well pump 110 via 103b. The well pump 110 draws wellbore drilling fluid from the drilling fluid tank 108 and directs the wellbore drilling fluid to the drilling rig 112, whereupon the wellbore drilling fluid flows into the formation through a drill string 112b and a drill bit 112c. The wellbore drilling fluid in the wellbore may be directed to a shaker system 114 at the surface of a geological formation 113 via 103c. The shaker system 114 may receive the wellbore drilling fluid, which may include cuttings (i.e., solid materials removed from the wellbore 111 during drilling) and other debris. The vibrator system 114 can separate cuttings and debris from the wellbore drilling fluid by directing the wellbore drilling fluid through a vibrating screen to allow the wellbore drilling fluid to be reused. The filtered wellbore drilling fluid can then be directed to the drilling fluid tank 108 via 103d, whereby the wellbore drilling fluid circulation process continues. The flow paths 103a-103d can be configured as piping and / or tubing.

[0021] The borehole drilling fluid can be a water-based drilling fluid or an oil-based drilling fluid. In some embodiments, the water-based drilling fluid can include an aqueous component. Similarly, the aqueous component can include fresh water, salt water, brine, municipal water, formation water, produced water, well water, filtered water, distilled water, seawater and / or a combination thereof. The brine can include at least one of natural and / or synthetic brines, such as saturated brine or formate brine. In some embodiments, the oil-based drilling fluid can include a hydrocarbon component. The hydrocarbon component can include diesel, kerosene, fuel oil, crude oil, mineral oil or a combination thereof. In an embodiment, the oil-based drilling fluid can additionally include an aqueous component as described above.

[0022] Other additives may be included in the borehole drilling fluid of the present disclosure. Such additives may include, but are not limited to, proppants, tackifiers, pH regulators, wetting agents, corrosion inhibitors, scale inhibitors, deoxidizers, antioxidants, biocides, surfactants, dispersants, interfacial tension reducers, mutual solvents, diluents, demulsifiers, crosslinking agents and combinations thereof. The characteristics and uses of the additives are not particularly limited and may be any suitable additive known to those of ordinary skill in the art. With the benefit of this disclosure, it will be appreciated by those of ordinary skill in the art that the addition of a particular additive will depend on the application and performance required for one or more embodiments of the borehole drilling fluid.

[0023] The wellbore drilling system 100 also includes an additive dispensing assembly 106, which is fluidly coupled to the drilling fluid tank 108 via 103e. The flow path 103e can be configured as a pipe and / or a pipeline. The additive dispensing assembly 106 can contain one or more additives with different chemical functions, for example, hydrogen sulfide scavengers, corrosion inhibitors, biocides, chlorinating agents, and other functional agents. The additive dispensing assembly 106 is coupled to the drilling fluid tank 108 to transfer a certain amount of additives in the additive dispensing assembly 106 to the drilling fluid tank 108. The additives received by the drilling fluid tank 108 are mixed with the wellbore drilling fluid in the drilling fluid tank 108, thereby "making up" the wellbore drilling fluid to cope with the reduction in the concentration of the additive in the wellbore drilling fluid.

[0024] Specifically, additives may be introduced into the wellbore drilling fluid prior to commencing drilling operations to mitigate the effects of TSR reactions and improve drilling operations. Over time, the wellbore drilling fluid may be "replenished," i.e., the concentration of the additive in the wellbore drilling fluid may be increased so that the additive may continue to provide the desired function throughout the drilling operations in the wellbore 111.

[0025] As described above, additives are added to the drilling fluid tank 108, and the solution of wellbore drilling fluid and additives is introduced into the wellbore at the drilling rig 112. Because additives may be lost during circulation through the wellbore, the concentration of additives in the wellbore drilling fluid directed from the well pump 110 to the drilling rig 112 may be greater than the concentration of additives in the wellbore drilling fluid directed from the wellbore 111 and into the vibrator system 114. As the vibrator system 114 removes drill cuttings and debris from the wellbore drilling fluid, the amount of additives in the wellbore drilling fluid may decrease. Therefore, the concentration of additives in the wellbore drilling fluid directed from the vibrator system 114 to the drilling fluid tank 108 may be less than the concentration of additives in the wellbore drilling fluid flowing out of the drilling rig 112 and into the vibrator system 114. Additives from the additive dispensing assembly 106 may be directed into the wellbore drilling fluid in the drilling fluid tank 108 to maintain or increase the concentration of additives in the wellbore drilling fluid.

[0026] The wellbore drilling system 100 also includes a computing device 104 coupled to an additive dispensing assembly 106. In some implementations, the computing device 104 may be implemented as a computer system including a memory component 120 and a processor 122 to perform the operations described in this disclosure.

[0027] In some embodiments, the computing device 104 may receive drilling parameters identifying a wellbore drilling condition of the wellbore drilling system 100. In some embodiments, the wellbore drilling system 100 may include one or more sensors 116 to monitor the concentration of one or more additives in the wellbore drilling fluid (e.g., 116a in the drilling fluid tank 108, 116b in the well pump 110, 116c in the wellbore 111, and / or 116d in the vibrator system 114), and the sensors may report the concentration to the computing device 104. In addition, the computing device 104 may send instructions to the well pump 110 to adjust the flow rate of the wellbore drilling fluid from the drilling fluid tank 108 to the wellbore 111. In embodiments, the flow rate of the pump may be varied to vary the volume of the wellbore drilling fluid in the wellbore. Some embodiments may be configured such that the computing device 104 calculates a TSR indicator value, as described in more detail below. Based in part on the received drilling parameters and the calculated TSR index value, the computing device 104 may determine the type and / or amount of additives to be included in the wellbore drilling fluid in the drilling fluid tank 108. In addition, the computing device 104 may control the additive dispensing assembly 106 to release the determined additive into the drilling fluid tank 108 to constitute the wellbore drilling fluid.

[0028] Figure 2An additive dispensing assembly 106 and other components of a wellbore drilling system according to one or more embodiments shown and described herein are depicted. As shown, a computing device 104 is operably coupled to the additive dispensing assembly 106, which may include one or more reservoirs 202 containing one or more additives. For example, the reservoirs 202 may include a hydrogen sulfide scavenger reservoir 202a storing a hydrogen sulfide scavenger compound, a corrosion inhibitor reservoir 202b storing a corrosion inhibitor compound, and / or one or more additional reservoirs, such as a biocide reservoir containing one or more biocide chemicals or a chlorinating agent reservoir containing one or more chlorinating agents.

[0029] In some embodiments, the additive dispensing assembly 106 may have only one reservoir 202, such as a hydrogen sulfide scavenger reservoir 202a. In some embodiments, the additive dispensing assembly 106 may have two reservoirs 202, such as a hydrogen sulfide scavenger reservoir 202a and a corrosion inhibitor reservoir 202b. In some embodiments, the additive dispensing assembly 106 may have more than two reservoirs, which may include a hydrogen sulfide scavenger reservoir 202a, a corrosion inhibitor reservoir 202b, a biocide reservoir containing one or more biocide chemicals, a chlorinating agent reservoir containing one or more chlorinating agents, and / or a combination reservoir containing any combination of hydrogen sulfide scavengers, corrosion inhibitors, biocides, and / or chlorinating agents.

[0030] The additive dispensing assembly 106 and the reservoir 202 are connected to the drilling fluid tank 108 in such a manner that the additive released from the additive dispensing assembly 106 is directed into the drilling fluid tank 108 to mix with the wellbore drilling fluid. In some embodiments, each additive dispensing assembly 106 may include a valve 204 that may be actuated in response to a signal from the computing device 104. Based on the physical properties (e.g., weight, density, volume, and / or other physical properties) of each additive type in each reservoir 202, the computing device 104 may actuate the valve for a duration sufficient to release a determined amount of the additive into the drilling fluid tank 108. By opening or closing the valve of each reservoir 202 for an appropriate duration, the computing device 104 may add the desired amount of different types of additives to replenish the wellbore drilling fluid to a level sufficient to improve the efficiency and safety of wellbore drilling.

[0031] Specifically, the hydrogen sulfide scavenger introduced into the wellbore drilling fluid can reduce the concentration of hydrogen sulfide present in the wellbore 111, which can reduce the toxicity and environmental impact of hydrogen sulfide production. Non-limiting examples of hydrogen sulfide scavengers can include oxidants, such as inorganic peroxides (such as sodium peroxide or chlorine dioxide), aldehydes or dialdehydes (such as C1-C 10The invention relates to hydrogen sulfide scavengers, which are preferably selected from the group consisting of hydroxyalkyl hydantoins, bis(hydroxyalkyl)hydantoins, and dialkyl hydantoins, wherein the alkyl group is a C1-C6 alkyl group. Other non-limiting examples of hydrogen sulfide scavengers include iron salts, such as iron oxides and / or iron hydroxides, both of which can react with hydrogen sulfide gas to form iron sulfides. Corrosion inhibitors introduced into the wellbore drilling fluid can reduce corrosion in the wellbore 111 and / or production facilities. Hydrogen sulfide acidifies the water present in the wellbore, which leads to increased corrosion of the drill pipe and equipment. Therefore, if left untreated, higher concentrations of hydrogen sulfide in the wellbore may lead to greater amounts of corrosion in the drill pipe and equipment. Therefore, increased amounts of corrosion inhibitor compounds can be added to the wellbore drilling fluid to reduce the corrosion rate in the wellbore. Non-limiting examples of corrosion inhibitors can include amidoamines, quaternary amines, amides, phosphates, or combinations thereof. Biocide compounds introduced into wellbore drilling fluids can inhibit biofilm and corrosion caused by microorganisms.

[0032] The fluid compressor 206 may be connected to one or more reservoirs 202. The computing device 104 may instruct the fluid compressor to start based on the processed data and the determined amount of each additive from each reservoir 202. Once the desired amount or concentration of additive is present in the drilling fluid tank 108 or other area of ​​the drilling system, the computing device 104 may stop the fluid compressor 206. In some cases, each reservoir 202 may include one or more weight sensors 208 to determine the amount of additive in each reservoir 202 and the need for refilling.

[0033] The computing device 104 may be configured to receive drilling parameters from one or more sensors 116 that identify the borehole drilling conditions of the borehole drilling system 100. The computing device 104 may calculate the TSR indicator value based on the conditions and / or characteristics of the borehole, the drilling parameters, the borehole modeling, and / or the measured borehole conditions. Non-limiting variables used in the TSR indicator calculation may include the depth of the borehole being drilled in the underground formation, the quality of anhydrite in the borehole, the concentration of hydrogen sulfide, the hydrocarbon composition and volume, the age of the formation, the burial history and thermal history of the formation, and the kinetic parameters of the TSR, wherein each corresponding variable may be modeled and / or measured. In an embodiment, at least one variable may be used in the TSR indicator calculation, such as the depth of the borehole being drilled in the underground formation.

[0034] Figure 3A computing device 104 of a borehole drilling system 100 is depicted in accordance with one or more embodiments shown and described herein. As shown, the computing device 104 includes a processor 122, input / output hardware 332, network interface hardware 334, a data storage component 336 (which stores well data 338a, command data 338b, and / or other data), and a memory component 120. The memory component 120 can be configured as volatile and / or non-volatile memory, and thus can include random access memory (including SRAM, DRAM, and / or other types of RAM), flash memory, secure digital (SD) memory, registers, compact disks (CDs), digital versatile disks (DVDs), and / or other types of non-transitory computer-readable media. Depending on the particular embodiment, these non-transitory computer-readable media can reside within the user computing device 104 and / or outside the user computing device 104.

[0035] The memory component 120 can store the operation logic 342, the calculation logic 344a and the drive logic 344b. The calculation logic 344a and the drive logic 344b can each include a plurality of different logic blocks, for example, each logic can be embodied as a computer program, firmware and / or hardware. The local interface 346 is also included in Figure 3 and may be implemented as a bus or other communication interface to facilitate communication between components of the user computing device 104.

[0036] Processor 122 may include any processing component operable to receive and execute instructions, such as instructions from data storage component 336 and / or memory component 120. Input / output hardware 332 may include and / or be configured to interface with sensors, microphones, speakers, displays, and / or other hardware associated with the wellbore.

[0037] The network interface hardware 334 may include and / or be configured to communicate with any wired or wireless network hardware, including antennas, modems, LAN ports, wireless fidelity (Wi-Fi) cards, WiMax cards, ZigBee cards, Bluetooth chips, USB cards, mobile communication hardware, and / or other hardware for communicating with other networks and / or devices. Through such connections, communication between the user computing device 104 and other devices and / or sensors may be facilitated.

[0038] The operating logic 342 may include an operating system and / or other software for managing components of the user computing device 104. As described above, the computing logic 344a and the driver logic 344b may reside in the memory component 120 and may be configured to perform the functions described herein.

[0039] It should be understood that although Figure 3The components in are illustrated as being stored within the user computing device 104, but this is merely an example. In some embodiments, one or more components may be stored outside the user computing device 104. It should also be understood that although the user computing device 104 is illustrated as a single device, this is merely an example. In some embodiments, the computing logic 344a and the drive logic 344b may be stored on different computing devices. For example, one or more functions and / or components described herein may be provided by the user computing device 104 and / or other devices (such as the wellbore system 100), which may be coupled to the user computing device 104 via a network.

[0040] In addition, although the user computing device 104 is illustrated as having the computing logic 344a and the driving logic 344c as separate logical components, this is also an example. In some implementations, a single logic block (and / or several linked modules) may enable the user computing device 104 to provide the described functionality.

[0041] As described above, the computing device 104 receives drilling parameters from one or more sensors 116 that measure one or more drilling parameters. For example, the sensor 116 may measure the mechanical rate of penetration of the drill bit, the flow rate of the wellbore drilling fluid through the wellbore drilling system 100, the concentration of additives present in the wellbore drilling fluid, and the concentration of hydrogen sulfide in the wellbore, to name a few. Additional drilling parameters that may be measured by one or more additional sensors 116 may include, for example, the percentage of drill cuttings coming out of the vibrator system 114, the concentration of additives in the wellbore drilling fluid flowing from the well pump 110 to the drilling rig 112, the concentration of additives in the wellbore drilling fluid flowing from the drilling rig 112 to the vibrator system 114, and the concentration of additives in the wellbore drilling fluid flowing from the vibrator system 114 to the drilling fluid tank 108. In some embodiments, the system may include one or more hydrogen sulfide sensors operable to quantify the concentration of hydrogen sulfide at a specific location within a subterranean formation. In an embodiment, the computing device 104 may receive a measured hydrogen sulfide concentration in the wellbore, compare the measured hydrogen sulfide concentration to a concentration predicted based on the TSR indicator, and adjust the TSR indicator calculation based on the measured concentration to calibrate the model.

[0042] The computing device 104 may store one or more models that identify the desired concentration values ​​of each corresponding additive to the wellbore drilling fluid and the concentration of the additive that needs to be added to the drilling fluid tank 108 to achieve each desired concentration. Further, the computing device 104 may store one or more models that predict the concentration of hydrogen sulfide gas present in the wellbore based on the wellbore depth, hydrocarbon composition and volume, the availability of anhydrite in the wellbore, the TSR index value, and / or other drilling parameters. In an embodiment, the computing device 104 may determine the corrosion parameter based in part on the hydrogen sulfide concentration, the wellbore depth, temperature, hydrocarbon composition and volume, the availability of anhydrite in the wellbore, the TSR index value, and / or other drilling parameters. The corrosion parameter can be used to predict the amount of corrosion inhibitor compound that can be added to the wellbore drilling fluid to reduce corrosion of the wellbore drilling system components. In response to a greater corrosion parameter value, an increased amount of the corrosion inhibitor compound can be added to the wellbore drilling fluid.

[0043] The computing device 104 may use the calculated or measured hydrogen sulfide concentration to determine an amount of hydrogen sulfide scavenger additive to add to the drilling fluid tank 108 to achieve a predetermined concentration of hydrogen sulfide scavenger in the wellbore drilling fluid.

[0044] In an embodiment, the computing device 104 may determine a change in the concentration of an additive in the wellbore drilling fluid that has been circulated through the wellbore drilling system 100. For example, based on the wellbore drilling fluid flow rate and the concentration of the additive in the wellbore drilling fluid, the computing device 104 may determine that the concentration of the additive has decreased from an initial concentration. In response, the computing device 104 may determine an amount of the additive to be added to the wellbore drilling fluid to replenish the lost concentration. In addition, the computing device 104 may identify different additive types (e.g., hydrogen sulfide scavengers and corrosion inhibitors) and the amount of each additive type to be added to the wellbore drilling fluid.

[0045] In embodiments, the computing device 104 may use the drilling parameters received from the sensors, the TSR indicator values ​​calculated from the TSR indicators, the calculated hydrogen sulfide concentration in the wellbore, and / or the corrosion parameters to detect that the concentration of one or more additives in the wellbore drilling fluid is below a desired concentration. In response, the computing device 104 may determine an additional amount of the additive to be added to the wellbore drilling fluid to change the concentration of the additive in the wellbore drilling fluid.

[0046] In an embodiment, the computing device 104 may store logic (e.g. Figure 3The calculation logic 344a and / or drive logic 344b in the wellbore drilling system 100, when executed by the processor 122, causes the wellbore drilling system 100 to perform at least the following operations: receive drilling parameters that identify wellbore drilling conditions of the wellbore drilling system; calculate a thermochemical sulfate reduction (TSR) index value for the wellbore, wherein the TSR index value is capable of predicting the progress of the TSR reaction in the wellbore, and the TSR index value is capable of predicting the concentration of hydrogen sulfide in the wellbore; if the predicted hydrogen sulfide concentration is above a first threshold, determine a first amount of a first additive to be added to the wellbore drilling fluid; combine the first amount of the first additive with the wellbore drilling fluid; determine a corrosion parameter based on the predicted hydrogen sulfide concentration in the wellbore; if the corrosion inhibitor is above a second threshold, determine a second amount of a second additive to be added to the wellbore drilling fluid; and combine the second amount of the second additive with the wellbore drilling fluid.

[0047] Figure 4A representative process of an embodiment described herein is depicted. In box 410, drilling parameters may be received. The drilling parameters may include, but are not limited to: a mechanical penetration rate of the drill bit into the formation 111, a flow rate of the wellbore drilling fluid through the wellbore, a depth of the wellbore being drilled in the underground formation, and a temperature of the underground formation. In box 420, a thermochemical sulfate reduction (TSR) indicator value may be calculated. As described above, the TSR indicator value may be calculated based on the depth of the wellbore being drilled in the underground formation, the mass of anhydrite in the wellbore, and the hydrocarbon composition and volume, wherein each corresponding variable may be modeled and / or measured. In box 430, the concentration of hydrogen sulfide in the wellbore may be predicted based on the TSR indicator value. The prediction takes into account the calculated progress of the TSR reaction that produces hydrogen sulfide in the wellbore, as well as the estimated volume of the wellbore, to calculate the predicted concentration of hydrogen sulfide in the wellbore. In box 440, if the predicted hydrogen sulfide concentration meets a predetermined threshold, a first amount of a first additive to be added to the wellbore drilling fluid may be determined. The first amount of the first additive can be determined based on the expected concentration of the first additive in the wellbore drilling fluid, the current concentration of the first additive in the wellbore drilling fluid, and the volume of the wellbore drilling fluid in the drilling fluid tank 108. In box 450, based on the predicted hydrogen sulfide concentration, a corrosion parameter can be determined. The corrosion parameter can be used to quantify the corrosion rate in the wellbore. The corrosion parameter can be determined based on the predicted hydrogen sulfide concentration and the temperature of the wellbore. Methods known in the art for simulating H2S corrosion can also be implemented to calculate the corrosion parameter. For example, Sun, W., Nesic, S. reported a mechanistic model of steel corrosion with hydrogen sulfide concentration and temperature in "A mechanistic model of H2Scorrosion of mild steel.Corrosion.NACE-07655.(2007)". In box 460, if the corrosion parameter is above a predetermined threshold, a second amount of the second additive to be added to the wellbore drilling fluid can be determined. The second amount may be determined based on a desired concentration of the second additive in the wellbore drilling fluid, a current concentration of the second additive in the wellbore drilling fluid, and a volume of the wellbore drilling fluid in the drilling fluid tank 108. In block 470, instructions may be sent to the additive dispensing assembly 106 to add a first amount of the first additive to the wellbore drilling fluid. In block 480, instructions may be sent to the additive dispensing assembly 106 to add a second amount of the second additive to the wellbore drilling fluid.

[0048] For example, the general reaction of TSR can be written as:

[0049] Sulfate + oil = calcite + H2S + H2O ± CO2 ± S ± altered oil (1)

[0050] TSR kinetic parameters describing reaction rates can be used to quantify the process and extent of TSR reactions. TSR reactions can be approximated as first-order kinetic reactions. The integrated first-order rate law can be expressed using the Arrhenius equation, which is used to extrapolate the rate constant at each temperature. The temperature-dependent rate constant (k Ci,t ) can be calculated as:

[0051]

[0052] Among them, A Ci It is component C i Arrhenius preexponential factor (mol / s), E a,Ci It is component C i is the activation energy (J / mol), T is the temperature (K), and R is the gas constant.

[0053] The cumulative TSR reaction is the integral of the TSR reaction rates for a specific component and temperature over a specific reaction duration. It can be written as:

[0054]

[0055] Among them, TSR Ci It is hydrocarbon component C i (For example, C1, C2, C3..., C i ) of the cumulative TSR reaction (mol / ton). k Ci,t It is C i The rate constant (mol / ton / s) of the TSR reaction at time t (s) and temperature (K). t0 and t1 are the start and end times of the TSR reaction, respectively.

[0056] In order to reduce the computational workload and improve efficiency, hydrocarbon components can be divided into four groups: dry gas (C1), wet gas (C2-C5), light oil (C6-C 14 ) and heavy oil (C 15 +). The TSR reaction rates are calculated based on these four groups rather than on each individual component. The rate constants (k Ci) can be calculated using the activation energy and frequency factor obtained from TSR experiments reported in the literature. For example, Yue, C., Li, S., Ding, K. and Zhong, N. reported the activation energy and frequency factor of C1 and C3 in "Thermodynamics and kinetics of reactions between C1-C3 hydrocarbons and calcium sulfate in deep carbonate reservoirs. Geochemical Journal, 40 (1), 87-94. (2006)". Zhang, T., Ellis, GS, Ma, Q., Amrani, A. and Tang, Y. reported the activation energy and frequency factor of light oil and heavy oil in "Kinetics of uncatalyzed thermochemical sulfate reduction by sulfur-free paraffin. Geochimica et Cosmochimica Acta, 96, 1-17. (2012)".

[0057] The TSR index can be calculated as i ) is the sum of the TSR reactions as follows:

[0058]

[0059] Among them, TSR P is the TSR index (mol / ton), n is the hydrocarbon component C i In addition, based on Equation 1, the amount of product H2S (g) and by-product CO2 (g) can be calculated as a function of the TSR index.

[0060] The hydrocarbons present in the wellbore 111 (excluding dry gas (CH4)) may be changed during the thermal cracking and TSR reaction to form smaller molecular compounds (Equation 1). For example, dry gas and wet gas may be produced from light oil and heavy oil. The altered hydrocarbons are taken into account and added to the relevant hydrocarbon group of the remaining amount. For example, the generated C1 needs to be added to the remaining C1 to form the total remaining C1 at the target time. The rate of generating altered hydrocarbons can be expressed as a function of the TSR reaction rate:

[0061]

[0062] in, It is hydrocarbon component C i Altered hydrocarbon components C jThe generation rate (mol / ton / s), a cj is the coefficient of positive correlation between the two rates. cj 0.5 and 0.6 respectively.

[0063] Altered hydrocarbons can be calculated using the following function:

[0064]

[0065] in, It is due to the light oil and heavy oil (hydrocarbon component C m+ ) produced by the alteration of hydrocarbon components C j Cumulative production (mol / ton).

[0066] The TSR reaction may include sulfates and hydrocarbons as reactants. Hydrocarbons are typically present in carbonate reservoirs. However, the abundance of anhydrite and its accessibility may limit the extent of the TSR reaction. Anhydrite sources in the reservoir may contain internal portions of anhydrite nodules that may be inaccessible to water and hydrocarbons. Therefore, the calcite produced by the TSR reaction formed around the anhydrite nodules may have a protective effect to prevent further reaction of the anhydrite core. Therefore, the unreacted core of the nodules is invalid (or non-reactive) anhydrite.

[0067] The amount of effective anhydrite (i.e., anhydrite that can potentially participate in TSR reactions) can be characterized and quantified by petrographic analysis of core samples and / or logging studies. For example, petrographic thin section analysis can characterize the particle size and type of anhydrite (whether it is small particles or agglomerates) and quantify it by point counting analysis. In cases where cores are not available, well logging can be used to characterize whether the anhydrite is thick or continuous thin layers alternating with limestone or dolomite. For thick or thin layers of anhydrite, different ratios of reactive anhydrite can be assigned; these ratios can be calibrated with data from nearby areas where information is available.

[0068] The consumption of effective anhydrite is a function of the TSR reaction according to the following equation:

[0069] 8C n H m + (4n+m)CaSO4(anhydrite) = (4n+m)CaCO3(calcite) + (4n+m)H2S(g) + (4n-m)CO2(g) + (3m-4n) / 2H2O (7)

[0071] The hydrocarbon composition (H / C ratio equals m / n) drives the stoichiometry of the reaction. The effective anhydrite can be calculated using the following equation:

[0072]

[0073] Among them, An r,t is the remaining effective anhydrite; i is the initial effective anhydrite; x Ci is the reaction stoichiometry. For example, the stoichiometry of dry gas (CH4) is 1. If we use C3 (C3H8) as a proxy for wet gas (C2-C5), the stoichiometry is 0.4 (8 / 20). 10 (C 10 H 22 ) as light oil (C6-C 14 ) indicator, the stoichiometric relationship value is 0.129 (8 / 62). 22 (C 22 H 46 ) as heavy oil (C 15 +), the stoichiometric relationship value is 0.060 (8 / 134). If the remaining anhydrite is less than or equal to 0, the simulated TSR reaction will stop.

[0074] Based on the equations for each TSR reaction above, the final formula for calculating the TSR indicator is:

[0075]

[0076] The parameters in the above equation have been described above. From the start of the TSR reaction (t0), An r,t Gradually decreases. r,t ≤0, the TSR reaction will stop, and then, the final TSR p TSR equal to t reaction time p,t .

[0077] According to Table 1, the TSR index can be used to estimate the risk factor of H2S in a specific part of the reservoir. The H2S risk factor is a function of the H2S concentration in the total gas produced by the reservoir. Operators can develop a ranking of risk factors and threshold levels of H2S concentration for different oil and gas fields based on operational safety, facility prevention, and economic assessment. The following table provides examples of risk factors ranging from 0 to 12 for H2S concentrations ranging from <0.1ppm to >10%.

[0078] Table 1

[0079] TSR Index <![CDATA[H2S concentration]]> <![CDATA[H2S risk coefficient]]> <0.1 <0.1ppm 0 (lowest risk) 0.1 10ppm 1 0.25 25ppm 2 0.5 50ppm 3 1.0 100ppm 4 2.5 250ppm 5 5.0 500ppm 6 10 1000ppm 7 100 1％ 8 200 2％ 9 500 5％ 10 1000 10％ 11 >1000 >10％ 12 (highest risk)

[0080] Example

[0081] In the following examples, as reported in Table 2, by using the activation energy (E a) and the frequency factor (A) are used to approximate the temperature-dependent TSR reaction rate for each hydrocarbon group.

[0082] Table 2

[0083]

[0084] Figure 5 A flow chart for the calculation of the TSR index value described further below is depicted. As indicated at block 510, the temperature-dependent TSR reaction rates of one or more hydrocarbon groups may be calculated. The temperature-dependent TSR reaction rates may be calculated using the temperature-dependent rate constants described in detail in Equation 2 above. Representative examples of temperature-dependent TSR reaction rates for wet gas from 50°C to 250°C are reported in Table 3 below.

[0085] Table 3

[0086]

[0087]

[0088] In box 520, after calculating the temperature-dependent TSR reaction rates of the four groups of hydrocarbons, the cumulative TSR reaction and hydrocarbon consumption of each group can be calculated according to equations 3, 6 and 8. As described above, hydrocarbon generation from the source rock formation can be calculated during the TSR reaction process. Further, at least a portion of the light oil produces additional dry gas and wet gas through alteration. In box 530, the altered hydrocarbons formed during the TSR reaction process can be calculated. Specifically, additional dry gas and wet gas can be calculated and added to the cumulative TSR reaction calculated for each corresponding group. In box 540, the availability of effective anhydrite can be calculated. For example, the calculation of the cumulative TSR reaction of light oil is shown in Table 4. The cumulative reaction at each temperature corresponds to the modeled depth below the surface of the wellbore 111.

[0089] Table 4

[0090]

[0091] In block 550, the cumulative TSR response for the hydrocarbon groups may be calculated at once. In block 560, a TSR index may be calculated according to Equation 9, which is the sum of the cumulative TSR for each group of hydrocarbons. The calculated TSR index is reported in Table 5 below.

[0092] Table 5

[0093]

[0094]

[0095] The calculated TSR index is a TSR proxy value that provides an assessment of the cumulative TSR response and the total H2S generation potential of the subsurface formation at the target depth, since H2S is a reaction product of the TSR reaction.

[0096] In the above exemplary embodiment, the computing device 104 receives the drilling parameters and calculates the TSR indicator value one or more times. In some embodiments, the computing device 104 can receive, calculate and process information in real time or near real time. Real time means that the duration of receiving continuous input or the duration of processing the received input and generating output is less than 1 millisecond or 1 nanosecond, depending on the specifications of the processor 122. In some embodiments, the computing device 104 can process information in real time or near real time and provide output of processed information at different frequencies. For example, the computing device 104 can provide instructions, such as introducing additives into the drilling fluid tank 108 at regular time intervals (e.g., once per minute, once every 2 to 3 minutes, etc.) and / or at irregular time intervals (e.g., when the system changes). Alternatively or additionally, the computing device 104 can provide the concentration of the additive in the wellbore drilling fluid as an output (e.g., in real time or otherwise), for example, displayed by a display device or transmitted to a remote computer system 118. As described above, the output may provide a determination of additive loss experienced during wellbore drilling operations and instruct the wellbore drilling system 100 to take corrective action.

[0097] Therefore, the embodiments provided herein may include methods and systems for preparing wellbore drilling fluid and wellbore drilling. These embodiments may allow continuous and / or repeated monitoring of the wellbore by using an updateable wellbore TSR indicator model. These embodiments may allow "on the fly" adjustment of the wellbore drilling fluid during any stage of the wellbore operation. In addition, since the wellbore TSR indicator model and the computing system for executing the TSR indicator model and the wellbore drilling fluid adjustment can be integrated into the drilling mechanism, at least some embodiments are configured so that the computer system is not only a general-purpose computer, but also a part of the overall system of drilling hardware. In addition, due to the complexity of the calculation, the description of the data, the amount of data and / or the time sensitivity of providing data and implementing the solution are not executable by humans at all, the calculation and / or graphical description can only be performed by the computing device / system (or technical equivalent) described herein, and cannot be performed by humans. Therefore, the embodiments provided herein can be configured to predict the TSR reaction process in the wellbore and improve the drilling fluid formulation to mitigate the risks during the drilling operation, thereby improving the efficiency of oil production.

[0098] According to one aspect, alone or in combination with any other aspect, a wellbore drilling system includes a drilling fluid tank containing a wellbore drilling fluid for introduction into a wellbore, an additive dispensing assembly fluidically coupled to the drilling fluid tank containing a first additive, and a computing device communicatively coupled to the additive dispensing assembly. The computing device includes a processor and a memory assembly storing logic that, when executed by the processor, causes the wellbore drilling system to at least perform the following operations: receive drilling parameters identifying a wellbore drilling condition of the wellbore drilling system; calculate a thermochemical sulfate reduction (TSR) indicator value for the wellbore, wherein the TSR indicator value predicts the progress of a TSR reaction in the wellbore, and wherein the TSR indicator value predicts a concentration of hydrogen sulfide in the wellbore; and determine whether the predicted concentration of hydrogen sulfide satisfies a first threshold. In response to determining that the predicted concentration of hydrogen sulfide satisfies the first threshold, the wellbore drilling system at least performs the following operations: determine a first amount of a first additive to be added to the drilling fluid tank to increase the concentration of the first additive in the wellbore drilling fluid, and send instructions to the additive dispensing assembly to release the first amount of the first additive into the drilling fluid tank.

[0099] According to a second aspect, alone or in combination with any other aspect, wherein the additive dispensing assembly comprises a hydrogen sulfide scavenger reservoir containing a first additive.

[0100] According to a third aspect, alone or in combination with any other aspect, wherein the first additive is a hydrogen sulfide scavenger compound.

[0101] According to a fourth aspect, alone or in combination with any other aspect, the hydrogen sulfide scavenger compound comprises an inorganic peroxide, an aldehyde, a dialdehyde, a triazine, a hydantoin, an iron salt, or a combination thereof.

[0102] According to the fifth aspect, alone or in combination with any other aspect, wherein the additive dispensing component further includes a second additive; and wherein the computing device causes the wellbore drilling system to further perform at least the following operations: determine a corrosion parameter based on the predicted hydrogen sulfide concentration in the wellbore; determine whether the corrosion parameter satisfies a second threshold; in response to determining that the corrosion parameter satisfies the second threshold: determine a second amount of the second additive to be added to the drilling fluid tank to increase the concentration of the second additive in the wellbore drilling fluid; and send an instruction to the additive dispensing component to release a second amount of the second additive into the drilling fluid tank.

[0103] According to a sixth aspect, alone or in combination with any other aspect, wherein the additive dispensing assembly comprises a corrosion inhibitor reservoir containing a second additive (excluding the first additive).

[0104] According to a seventh aspect, alone or in combination with any other aspect, wherein the second additive is a corrosion inhibitor compound.

[0105] According to an eighth aspect, alone or in combination with any other aspect, wherein the second additive is a corrosion inhibitor compound comprising an amidoamine, a quaternary amine, an amide, a phosphate ester, or a combination thereof.

[0106] According to a ninth aspect, alone or in combination with any other aspect, wherein the additive dispensing assembly comprises a hydrogen sulfide scavenger compound, a corrosion inhibitor compound, a biocide, a chlorinating agent, or a combination of two or more thereof.

[0107] According to the tenth aspect, alone or in combination with any other aspect, the drilling parameters include the mechanical penetration rate of the drill bit, the flow rate of the wellbore drilling fluid through the wellbore, and the depth of the wellbore being drilled in the underground formation.

[0108] According to an eleventh aspect, alone or in combination with any other aspect, further comprising a hydrogen sulfide sensor for measuring the concentration of hydrogen sulfide in the wellbore, and the computing device adjusts the TSR indicator value based on the measured hydrogen sulfide concentration in the wellbore.

[0109] According to the twelfth aspect, alone or in combination with any other aspect, further comprising a well pump, the well pump pumping the wellbore drilling fluid from the drilling fluid tank to the wellbore drilling rig, and the computing device sends instructions to the well pump to adjust the flow rate of the wellbore drilling fluid.

[0110] According to the thirteenth aspect, alone or in combination with any other aspect, a method for preparing a wellbore drilling fluid, the method comprising causing a computing device to perform at least the following operations: receiving drilling parameters identifying wellbore drilling conditions of a wellbore drilling system; calculating a thermochemical sulfate reduction (TSR) index value for the wellbore, wherein the TSR index value predicts the progress of the TSR reaction in the wellbore, and the TSR index value predicts the concentration of hydrogen sulfide in the wellbore; in response to determining that the predicted hydrogen sulfide concentration meets a predetermined threshold: determining a first amount of a first additive to be added to the wellbore drilling fluid; and combining the first amount of the first additive with the wellbore drilling fluid.

[0111] According to a fourteenth aspect, alone or in combination with any other aspect, wherein the first additive is a hydrogen sulfide scavenger compound.

[0112] According to a fifteenth aspect, alone or in combination with any other aspect, the first additive comprises an inorganic peroxide, an aldehyde, a dialdehyde, a triazine, a hydantoin or a combination thereof.

[0113] According to the sixteenth aspect, alone or in combination with any other aspect, further comprising: determining a corrosion parameter based on a predicted hydrogen sulfide concentration in the wellbore; in response to determining that the corrosion parameter satisfies a second threshold: determining a second amount of a second additive to be added to the wellbore drilling fluid; and combining the second amount of the second additive with the wellbore drilling fluid.

[0114] According to a seventeenth aspect, alone or in combination with any other aspect, wherein the second additive is a corrosion inhibitor compound.

[0115] According to the eighteenth aspect, alone or in combination with any other aspect, further comprising: receiving a measured hydrogen sulfide concentration in the wellbore; and adjusting the TSR indicator value based on the measured hydrogen sulfide concentration.

[0116] According to a nineteenth aspect, alone or in combination with any other aspect, further comprising monitoring a concentration of the first additive in the wellbore drilling fluid.

[0117] According to the twentieth aspect, alone or in combination with any other aspect, further comprising: transmitting at least one of the following to a display device: a measured hydrogen sulfide concentration, a calculated hydrogen sulfide concentration, or a concentration of a first additive in the wellbore drilling fluid.

[0118] Having described the subject matter of the present disclosure in detail and with reference to specific embodiments thereof, it should be noted that the various details disclosed herein should not be understood to imply that these details are related to elements of essential components of the various embodiments described herein, even if specific elements are shown in each of the figures accompanying this specification. In addition, it is apparent that adjustments and changes may be made without departing from the scope of the present disclosure, including but not limited to the embodiments defined in the appended claims. More specifically, although some aspects of the present disclosure are identified herein as preferred or particularly advantageous, it is contemplated that the present disclosure is not necessarily limited to these aspects.

[0119] It should be noted that the expression "at least one" of a component, element, etc. herein should not be used to infer that the alternative use of the article "a" or "an" should be limited to a single component, element, etc.

[0120] It should also be noted that terms like "preferably," "usually," and "typically," when used herein, are not intended to limit the scope of the claimed invention or to imply that certain features are critical, essential, or even important to the structure or function of the claimed invention. Rather, these terms are merely intended to identify particular aspects of embodiments of the present disclosure, or to emphasize alternative or additional features that may or may not be used in a particular embodiment of the present disclosure.

[0121] It should be noted that one or more of the claims utilize the term "wherein" as a transitional phrase. For purposes of defining the present invention, it should be noted that this term is introduced in the claims as an open transitional phrase used to introduce a description of a series of features of the structure and should be interpreted in a similar manner to the more commonly used open introductory term "comprising."

Claims

1. A wellbore drilling system, the system comprising: a drilling fluid tank containing a wellbore drilling fluid for introduction into the wellbore; an additive dispensing assembly fluidly coupled to the drilling fluid tank, the additive dispensing assembly containing a first additive; and a computing device communicatively coupled to the additive dispensing assembly, the computing device comprising a processor and a memory component storing logic that, when executed by the processor, causes the wellbore drilling system to at least: receiving drilling parameters identifying a wellbore drilling condition of the wellbore drilling system; Calculate the thermochemical sulfate reduction (TSR) index value of the wellbore, wherein, The TSR indicator value predicts the progress of a TSR reaction in the wellbore, and wherein the TSR indicator value predicts the concentration of hydrogen sulfide in the wellbore; determining whether the predicted hydrogen sulfide concentration satisfies a first threshold; In response to determining that the predicted hydrogen sulfide concentration satisfies a first threshold: determining a first amount of the first additive to be added to the drilling fluid tank to increase a concentration of the first additive in the wellbore drilling fluid; and Instructions are sent to the additive dispensing assembly to release the first amount of the first additive into the drilling fluid tank.

2. The system according to claim 1, wherein: The additive dispensing assembly includes a hydrogen sulfide scavenger reservoir containing the first additive.

3. The system according to claim 1, wherein: The first additive is a hydrogen sulfide scavenger compound.

4. The system according to claim 3, wherein: The hydrogen sulfide scavenger compound comprises an inorganic peroxide, an aldehyde, a dialdehyde, a triazine, a hydantoin, an iron salt, or a combination thereof.

5. The system according to claim 1, wherein: The additive dispensing assembly further includes a second additive; and wherein the computing device causes the wellbore drilling system to further perform at least the following operations: determining a corrosion parameter based on a predicted hydrogen sulfide concentration in the wellbore; determining whether the corrosion parameter satisfies a second threshold; In response to determining that the corrosion parameter satisfies the second threshold: determining a second amount of the second additive to be added to the drilling fluid tank to increase the concentration of the second additive in the wellbore drilling fluid; and Instructions are sent to the additive dispensing assembly to release the second amount of the second additive into the drilling fluid tank.

6. The system of claim 5, wherein the additive dispensing assembly includes a corrosion inhibitor reservoir containing the second additive but not the first additive.

7. The system according to claim 5, wherein: The second additive is a corrosion inhibitor compound.

8. The system according to claim 5, wherein: The second additive is a corrosion inhibitor compound comprising an amidoamine, a quaternary amine, an amide, a phosphate ester, or a combination thereof.

9. The system according to claim 1, wherein: The additive dispensing assembly includes a hydrogen sulfide scavenger compound, a corrosion inhibitor compound, a biocide, a chlorinating agent, or a combination of two or more thereof.

10. The system according to claim 1, wherein: The drilling parameters include the mechanical penetration rate of the drill bit, the flow rate of the wellbore drilling fluid through the wellbore, and the depth of the wellbore being drilled in the underground formation.

11. The system of claim 1 , further comprising a hydrogen sulfide sensor that measures a concentration of hydrogen sulfide in the wellbore, and the computing device adjusts the TSR indicator value based on the measured hydrogen sulfide concentration in the wellbore.

12. The system of claim 1, further comprising a well pump that pumps the wellbore drilling fluid from the drilling fluid tank to a wellbore drilling rig, and the computing device sends instructions to the well pump to adjust the flow rate of the wellbore drilling fluid.

13. A method of preparing a wellbore drilling fluid, the method comprising causing a computing device to at least perform the following operations: receiving drilling parameters identifying a wellbore drilling condition of the wellbore drilling system; Calculate the thermochemical sulfate reduction (TSR) index value of the wellbore, where The TSR indicator value predicts the progress of a TSR reaction in a wellbore, and the TSR indicator value predicts the concentration of hydrogen sulfide in the wellbore; In response to determining that the predicted hydrogen sulfide concentration satisfies a predetermined threshold: determining a first amount of a first additive to be added to the wellbore drilling fluid; The first amount of the first additive is combined with the wellbore drilling fluid.

14. The method according to claim 13, wherein: The first additive is a hydrogen sulfide scavenger compound.

15. The method according to claim 13, wherein: The first additive comprises an inorganic peroxide, an aldehyde, a dialdehyde, a triazine, a hydantoin or a combination thereof.

16. The method according to claim 13, further comprising: determining a corrosion parameter based on a predicted hydrogen sulfide concentration in the wellbore; In response to determining that the corrosion parameter satisfies a second threshold: determining a second amount of a second additive to be added to the wellbore drilling fluid; and The second amount of the second additive is combined with the wellbore drilling fluid.

17. The method according to claim 16, wherein: The second additive is a corrosion inhibitor compound.

18. The method according to claim 13, further comprising: receiving a concentration of hydrogen sulfide measured in the wellbore; and The TSR index value is adjusted based on the measured hydrogen sulfide concentration.

19. The method of claim 13, further comprising monitoring a concentration of the first additive in the wellbore drilling fluid.

20. The method of claim 13, further comprising transmitting to a display device at least one of: a measured concentration of hydrogen sulfide, a calculated concentration of hydrogen sulfide, or a concentration of the first additive in the wellbore drilling fluid.

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