Method for reducing carbon dioxide and hydrogen sulfide

Abstract

To provide a method and system for reducing carbon dioxide (CO2) and / or hydrogen sulfide (H2S) in a geological layer.SOLUTION: Water is pumped or transferred from a water source to an injection well. Gas is merged with the water under conditions where the hydraulic pressure of the water is less than the pressure of CO2 and / or H2S gas at a merging point. The water containing CO2 and / or H2S gas bubbles is transferred further downwardly at a certain velocity higher than the upward flow velocity of the CO2 and / or H2S gas bubbles, causing the downward movement of the gas bubbles so that the CO2 and / or H2S in the water is completely dissolved due to elevating pressure. It is necessary that the pH of the water entering a geological layer (for example, a geothermal reservoir) is lowered by the complete dissolution, and mineral reactions leading to CO2 and / or H2S reduction are promoted. The amount of reduction can be quantified by dissolving a tracer substance in a predetermined molar ratio to the dissolved CO2 and / or H2S and is monitored in a monitoring well.SELECTED DRAWING: None

Description

[Technical field]

[0001] FIELD OF THEINVENTION The present invention relates to a method for producing carbon dioxide (CO 2 ) and hydrogen sulfide (H 2 S) into a geological reservoir for subsequent storage, and a method and system for reducing these gases. [Background technology]

[0002] 2. Background of the Invention Carbon Dioxide (CO 2 ) and hydrogen sulfide (H 2 S) are gases released in large quantities during various industrial processes, including the burning of fossil fuels. These two gases pose significant challenges for the environment.

[0003] Industrial CO 2 Reducing CO emissions from geothermal sources is one of the major challenges of this century (Ref.1: Broecker and Kunzig). 2 The relatively small emissions make them classed as renewable energy, in contrast to conventional fossil fuel power plants, which buy and sell permits (called "emissions allowances") to prevent pollution.

[0004] Conventional geothermal power plants harness the earth's heat using a high-temperature mixture of steam and brine from geothermal reservoirs characterized by thermal anomalies, permeable rocks, and fluids (Ref. 2: Barbier). Geothermal steam from these reservoirs contains CO, a greenhouse gas. 2 and hydrogen sulfide (H 2 Geothermal water naturally contains dissolved gases, including both argon and argon. These gases are a by-product of geothermal energy production and are of magmatic origin. When a conventional geothermal power plant is operational, the gases in the steam are vented into the atmosphere.

[0005] Until now, geothermal power plants have been known to emit little greenhouse gas, so CO 2However, as climate change policies become stricter, 2 The price of emissions is expected to rise.

[0006] Hydrogen sulfide emissions from geothermal power plants are one of the environmental concerns in geothermal energy. Hydrogen sulfide is a colorless, flammable, toxic gas with a characteristic rotten egg odor. Exposure to hydrogen sulfide can cause health problems depending on the level and duration. Low levels and long-term exposure can cause eye irritation and inflammation, while high levels and short-term exposure can cause dizziness, headaches, nausea, and contribute to the release of atmospheric H 2 S concentrations above 300 ppm can be fatal.

[0007] Concentrations of hydrogen sulfide in geothermal fluids typically range from a few ppb to hundreds of ppm (Ref. 3 + 4: Arnorsson). When using high-temperature geothermal fluids, hydrogen sulfide is concentrated in the vapor phase and released into the atmosphere after the vapor condenses. For example, the Hellisheioi power plant in Iceland releases 9,500 tonnes of hydrogen sulfide into the atmosphere per year, with no measures in place. Hydrogen sulfide is released above the cooling towers to reduce the risk of high concentrations of hydrogen sulfide near the plant. The hydrogen sulfide is carried away by the wind away from the plant site and, depending on the weather, can cause odors in nearby communities.

[0008] To this day, 2 It has been stored as a supercritical fluid in connection with major gas and oil production facilities such as Sleipner in the North Sea, In Salah in Algeria, and Weyburn in Canada (Ref. 5: Kerr). In any case, CO released into the atmosphere, whether due to geothermal or other power plants, 2 In order to reduce the amount of CO in underground structures, 2 The standard method for underground carbon storage and sequestration involves storing CO in geological formations at depths of 800 m or more. 2 At this depth, CO2 is in a supercritical state and is buoyant relative to the host rock fluid. As a result, the buoyant CO 2 may fall back into the shallow underground or to the surface (Ref. 6: Hawkins; Ref. 7: Benson).

[0009] Gislason et al. (Ref. 8) reported that CO was transported as high-pressure gas via a 3 km pipeline to a pilot injection site. 2 The method envisaged is to capture CO 2 is injected together with water, and the injected CO 2 The authors of this publication report that a single fluid phase will enter the sequestration layer, resulting in a single fluid phase entering the sequestration layer. Similarly, Sigfusson et al. (Ref. 16) reported that approximately 175 tonnes of CO 2 Similarly, Sigfusson et al. (Ref. 16) reported that about 175 tonnes of CO dissolved in 5000 tonnes of water was injected. 2 (at a depth of about 350 m below the surface) into porous rock 400–800 m below the surface, and this method 2 Even though a large amount of water is required to store CO 2 Since it is dissolved, it has no buoyancy, and supercritical CO 2 Similarly, Gunnarson et al. (Ref. 17) investigated the storage of CO at temperatures of 200–260 °C in basalt rocks about 2000 m below the surface. 2 and H 2 They describe the continuous injection of S (dissolved in water at a depth of about 750 m below the surface), which, due to its great depth and high temperature, produces larger amounts of CO than would be possible if injected into a shallower, cooler rock formation. 2 and H 2 This points out the fact that it is possible to inject S.

[0010] The methods detailed in these publications are different from the method of the present invention. Thus, both of these publications involve the determination of the downward velocity of the water flow and the CO released as bubbles of a given size at the confluence. 2 and / or H 2 The authors fail to point out the importance of the relationship between the ability to efficiently ensure that CO is maintained in solution at a given depth / pressure. 2 and / or H 2 The water is mixed with the S-rich gas stream and then mixed with CO dissolved in the water. 2 and / or H 2 The publication is silent on the importance of transporting the S gas bubbles downward at a higher velocity than the upward velocity. In fact, quite the opposite (Ref. 16) merely points out more generally the importance of dissolving the carbon dioxide in water during injection, and mentions typical volumetric flow rates and mean residence times, but does not give any detailed information on the relative velocity of the water and CO2. 2 The authors focus on the importance of maintaining a constant mass ratio. This means that the factors influencing the usefulness of such a process were not fully understood by the authors at the time. Similarly, none of these publications point out the relevant discovery of the present invention that water demand can be reduced simply by increasing the downward flow rate of water. This feature is of great economic importance to the feasibility of the process of the present invention compared to the processes described in the prior art.

[0011] Sanopoulos and Karabelas are working on H at geothermal power plants, etc. 2 A review of processes available for reducing S is underway (Ref. 9). Most of the known methods involve H 2 It is the oxidation of S to elemental sulfur and sulfuric acid. The value of these products is low because there is little demand or an oversupply. Disposal of these products is costly and can cause environmental problems.

[0012] Hibara et al. (Ref.10) have proposed a method in which hydrogen sulfide is compressed, mixed with brine, and reinjected into auxiliary wells. However, such hydrogen sulfide removal methods have not been described in detail, and the factors that affect the usefulness of such methods are not fully understood.

[0013] For these reasons, CO emissions, whether from geothermal power generation or other power plants, 2 and H 2 It can be seen that there is a need for new cost-effective and environmentally friendly methods for reducing CO 2 and H 2 They have discovered a new method to facilitate the safe and permanent geological storage of S. This method can significantly reduce water demand by increasing the downward flow rate of water, e.g., CO 2 and H 2 One can simply reduce the diameter of the pipe surrounding the junction of the S-rich gas stream and the water. Thus, for a given junction and a given flow rate of water, the amount of CO dissolved in the injected water can be reduced. 2 and H 2 By simply controlling the amount of S gas, 2 and H 2 It can facilitate safe long-term storage of S. Summary of the Invention [Problem to be solved by the invention]

[0014] Summary of the Invention As discussed above, it would be advantageous to have an effective and environmentally friendly method for reducing carbon dioxide and hydrogen sulfide emissions from conventional and geothermal power plants. In general, the invention seeks to mitigate, alleviate or eliminate one or more of the above mentioned disadvantages singly or in any combination. [Means for solving the problem]

[0015] To better address one or more of these concerns, in a first aspect of the present invention, a carbon dioxide (CO 2 ) and / or hydrogen sulfide (H 2 A method for storing hydrogen peroxide (S) in a geological reservoir is provided, comprising: · Pumping (or otherwise transporting) water from the water source to the injection well; Water pressure, CO 2 and / or H 2 CO in S-rich gas streams 2 and / or H 2 Under conditions where the partial pressure of S is lower than that of CO 2 and / or H 2 By combining the S-rich gas stream with water, 2 and / or H 2 Dissolving S gas in water; Dissolved CO 2 and / or H 2 Water containing S was mixed with CO in water. 2 and / or H 2 The CO dissolved in the water is transported downward at a rate faster than the upward rate of the S gas bubbles. 2 and / or H 2 To ensure the retention of S; Dissolved CO 2 and H 2 maintaining the resultant pH value of said S-containing pressurized water stream at about 2 to 4, preferably at about 2.5 to 3.5, more preferably at about 3.2; and CO 2 and / or H 2 Injection of water containing dissolved S into a geological reservoir.

[0016] In the context of the present invention, the term pump should be understood as any means for transporting a liquid, such as water, from one place to another.

[0017] In the context of the present invention, the term water source or water is to be understood as any kind of water, such as, for example, groundwater, sea / ocean water, spring water, geothermal condensate or brine, or surface water from rivers, streams, lakes, etc.

[0018] In the context of the present invention, the term injection well is understood to mean any type of structure that offers the possibility of putting fluids or gases deep underground or downwards into the earth, for example into reactive rock formations such as basalt or basalt, into porous rock formations such as sandstone or limestone, or into or under shallow soil layers.

[0019] In the context of the present invention, CO 2 and / or H 2 The S-rich gas stream is CO 2 and / or H 2 The relative content of S in the atmosphere 2 and / or H 2 It is understood that the gas stream has a higher relative content of S.

[0020] In the context of this invention, the term hydraulic (water pressure) is understood as the pressure that a hydraulic fluid (operating liquid) exerts in all directions on a vessel, well, hose, or whatever it is in. Hydraulic pressure can cause flow in hydraulic systems when a fluid flows from higher pressure to lower pressure. Pressure is measured in SI units of Pascal (Pa), i.e. 1 Newton per square meter (1N / m 2 ), 1kg / (m s 2 ) or 1 J / m 3 Other commonly used units of pressure are pounds per square inch, or more precisely pounds-force per square inch (abbreviated as psi), and bars. In SI units, 1 psi is approximately equal to 6895 Pa, and 1 bar is approximately equal to 100,000 Pa.

[0021] In the context of the present invention, (CO 2 and / or H 2 The term partial pressure of a gas (S) or simply pressure is to be understood as the assumed pressure of a given gas in a mixture of gases if this given gas by itself occupied the entire volume of the original mixture at the same temperature. The total pressure of an ideal gas mixture is the sum of the partial pressures of the individual constituent gases in the mixture.

[0022] In the context of the present invention, the term velocity should be understood as a vector quantity, meaning the speed at which an object changes its position in a certain direction. Thus, velocity is equal to distance / time and has the SI unit m / s. Water moving in a given direction with a given velocity moves with a constant flow rate. This flow rate is provided as a volumetric flow rate or a mass flow rate. Volumetric flow rate is the volume of fluid passing a point per unit time and is usually represented by the symbol Q (sometimes V). The SI unit of volumetric flow rate is m 3 / s. Thus, volumetric flow rate is equal to volume / time. On the other hand, mass flow rate is the mass of fluid passing a given point per unit time (kg / s).

[0023] In the context of the present invention, "injection" or "injection" is understood as the forcible introduction of something into something else, i.e. the forcible introduction of a fluid into an underground structure.

[0024] In the context of the present invention, the term geothermal reservoir should be understood as fractures in underground structures, for example basalt, that expand in directions other than upwards and downwards, which structures provide a flow path for the water injected into the injection well according to the present invention, and may include those called geothermal reservoirs. In this context, the term geothermal reservoir should be understood as fractures in hot rock that expand in directions other than upwards and downwards, which provide a flow path for the water injected from the well.

[0025] In the method and system of the present invention, dissolved CO 2 and / or H 2 The pressure of S becomes less than the pressure of water (thereby keeping it in solution), so CO 2 and / or H 2 The S remains dissolved in the water, reducing the risk of leakage and significantly improving safety. The method according to the invention also allows for a significant reduction in water demand by increasing the downward flow rate of water. For example, CO 2 and / or H 2One can simply reduce the diameter of the pipe surrounding the junction of the S-rich gas stream and the water. 2 The injection of CO promotes carbonization of the host rock and reduces CO 2 Therefore, the water-rock reactions occurring in the naturally reactive rocks of geothermal systems, e.g. basalt reservoirs, can be used to store CO 2 and / or H 2 A method is provided for utilizing S by injecting it into a geothermal reservoir system. This allows CO emissions from geothermal power plants, etc. 2 Or H 2 The impact of S gas on the environment can be reduced. 2 Or H 2 Safe long-term storage of S depends on how much CO2 is added to the injected water at a given confluence and a given rate of water fall. 2 Or H 2 This can be easily done by simply controlling how much S gas is dissolved.

[0026] Additionally, the reduction (removal) method of the present invention is very economical and environmentally friendly since there are no by-products that need to be disposed of. 2 Or H 2 Returning S to its original location is seen as an ideal way to reduce emissions from geothermal power plants and other sources.

[0027] In the method and system of the present invention, dissolved CO 2 and / or H 2 Because the gas pressure (i.e. partial pressure) of S is less than the water pressure (thereby keeping it in solution), the gas remains dissolved in the water and does not degas from the water. Thus, the method of the present invention minimizes the risk of gas bubbling out of the water, which would otherwise occur. 2 and / or H 2 S will not be effectively transported to the geological reservoir that is attempting to absorb and / or mineralize the gas.

[0028] At the same time, the water's low pH promotes dissolution of reservoir minerals and provides the cations necessary for carbon and sulfur mineralization and removal.

[0029] CO before injection into water 2 and / or H 2 Because the pressure of S is greater than the water pressure, gas bubbles will be present in the water at the confluence (i.e., the gas injection point); however, the gas bubbles are transported downward at the critical water velocity, ensuring that the gas flow dissolves in the water and remains dissolved, i.e., in solution.

[0030] In one embodiment, the step of dissolving a gas in water comprises dissolving CO 2 and / or H 2 The water pressure in the injection well at the open end of the injection tube causes the CO 2 and / or H 2 and conducting the gas through an injection tube having an open end extending downwardly into said injection well at a depth selected to be less than the pressure of the S gas. At the same time, water is transported downwardly at a velocity relative to the time the gas was injected into the injection well, whereby, for a given portion of the water flow, the hydraulic pressure of the water dissolves the dissolved CO gas relatively soon after the gas is injected into the water. 2 and / or H 2 S pressure. Thus, the CO 2 and / or H 2 To dissolve S gas in water, and CO 2 and / or H 2 The hydraulic pressure required to keep the S gas dissolved in the water is achieved by moving the water and gas to the appropriate depth, so no external energy is required at or below the confluence to achieve or maintain the necessary hydraulic pressure. 2 and / or H 2 When S is injected into the injection well (which is possible because the water pressure in the injection tube is greater than the water pressure in the injection well), at the open end, it does not start to "foam" after injection, but instead, CO 2 and / or H 2This ensures that the S-dissolved CO2 is kept dissolved, i.e., in solution, for the time frame required for the mineralization water-rock reaction to occur. This is similar to avoiding the scenario where, when a bottle of carbonated drink is opened, carbon dioxide begins to bubble out, resulting in the release of carbon dioxide from the bottle into the atmosphere. In this way, if the bottle is opened under ambient pressure equal to or greater than the pressure inside the bottle, no carbon dioxide bubbling will occur. The method according to the invention further provides for the prevention of the dissolution of CO2 dissolved therein. 2 and / or H 2 The presence of S allows the low pH of the water to promote dissolution of minerals in geological reservoirs, thereby providing the cations necessary for carbon and sulfur mineralization and mitigation.

[0031] In one embodiment, CO 2 and / or H 2 The step of dissolving S gas in water is 2 and / or H 2 The method includes delivering S gas through an injection tube having an open end extending into the injection well, the injection tube being surrounded by an outer tube having an open end disposed at a depth greater than the open end of the injection tube, and the water is pumped into a space between the outer tube and the injection tube. The depth of the opening of the injection tube in the outer tube is determined such that the water pressure in the outer tube at the opening of the injection tube is greater than the water pressure in the injection tube. 2 and / or H 2 S gas pressure is selected to be less than the pressure of the gas at the same time that the water is transported downward at a rate relative to the time the gas was injected into the injection well, and for a given portion of the water flow, the water pressure is selected to be less than the pressure of the dissolved CO relatively soon after the gas was injected into the water. 2 and / or H 2 Ensure that the sum of the partial pressures of S is greater than the sum of the partial pressures of S.

[0032] In one embodiment, the water pumping rate and pipe diameter are adjusted to reduce the drag of the downward flowing water to the injection well. 2 and / or H 2 The buoyancy of S is chosen to be greater than the buoyancy of S. Thus, a constant downward water flow is provided, which dissolves the dissolved CO2 and / or H 2 It is ensured that S moves downwards, towards the storage tank. A method or system for handling relatively small bubbles, e.g. bubbles with a diameter of 6 mm or less, according to the present invention requires a minimum water flow velocity between 0.4 m / s and 1.4 m / s depending on the dynamic forces in the system.

[0033] In one embodiment, CO at the open end of the injection tube 2 The gas pressure (i.e., the water pressure in the injection well) is 2 The pressure of the water (less than the pressure of the gas) is between 20 and 35 bar. At this pressure, the temperature of the water is between 20 and 40 °C, resulting in a single fluid phase entering a reservoir, for example but not limited to, relatively fresh basaltic lava.

[0034] In one embodiment, the depth at the open end of the outer tube is determined based on the pH value of the injected water containing dissolved CO. 2 is selected to be 2 to 4, preferably 2.5 to 3.5, and more preferably about 3.2. 2 and / or H 2 S leaves the outer tube, and CO 2 and H 2 It is at this depth that sequestration of S into rocks begins, i.e. carbon dioxide CO 2 and hydrogen sulfide H 2 The lower the pH value, the faster the rock dissolves, and the lower the pH value, the faster the CO2 storage in the reservoir (geological reservoir). 2 and hydrogen sulfide H 2 This will significantly promote the isolation of S.

[0035] In one embodiment, CO 2 and / or H 2 The step of dissolving S gas in water may be 2 and / or H 2 To obtain a homogeneous mixture of S gas in water, dissolved CO 2 and / or H 2S with the water below the confluence, e.g., using a sparger and / or mixer, to break down large air bubbles and remove any remaining CO2 in the water. 2 and / or H 2 This dissolves the S gas bubbles. 2 and / or H 2 Turbulence occurs in the mixture of S gas and pressurized water, and CO 2 and / or H 2 The dissolution of S gas is further promoted. 2 and / or H 2 The large bubbles of S break up into smaller bubbles and CO 2 and / or H 2 The dissolution of S is promoted.

[0036] In one embodiment, the water source is selected from one or more of surface water, ground water, or seawater.

[0037] In an embodiment, the water is 2 The step of dissolving the gas is 2 Gas and / or H 2 The method further includes maximizing the interfacial area between the S gas and the water, thereby preventing CO 2 and / or H 2 The S gas bubbles are evenly dispersed in the pressurized water, and the CO 2 and / or H 2 The interfacial area between the S gas and the water is maximized, reducing the average bubble diameter, and these factors increase the CO 2 and / or H 2 The dissolution rate of S is significantly improved.

[0038] In an embodiment, CO 2 and / or H 2 The step of dissolving S gas in the water comprises dissolving CO 2 and / or H 2 S is mixed with water and CO 2 and / or H 2 To obtain a uniform mixture of S gas and CO remaining in the water.2 and / or H 2 The method further includes dissolving bubbles of CO 2 and / or H 2 Turbulence occurs in the mixture of S gas and pressurized water, causing CO 2 and / or H 2 The dissolution of S gas is further promoted. Also, the large CO 2 and / or H 2 The S gas bubbles break down into smaller bubbles, and CO 2 and / or H 2 This will increase the dissolution rate of S.

[0039] In one embodiment, CO 2 and / or H 2 The step of dissolving S gas in water is 2 and / or H 2 The water pressure in the injection well at the open end of the injection tube causes the CO 2 and / or H 2 and conducting the gas through an injection tube having an open end extending downwardly into said injection well at a depth selected to be less than the pressure of the S gas. At the same time, water is transported downwardly at a velocity relative to the time the gas was injected into the injection well, such that for a given portion of the water flow, the hydraulic pressure of the water reduces the dissolved CO2 relatively soon after the gas was injected into the water. 2 and / or H 2 The water pressure is slightly less than the gas pressure at the confluence depth because, first, the CO 2 and / or H 2 The first is to allow the S gas to enter the water in the injection well at the confluence depth, and the second is to allow the water pressure at a slightly greater depth to dissolve in the water and move downward at a given downward velocity. 2 and / or H 2 Therefore, by selecting the depth of the confluence of the injection wells and the rate of water descent, the CO pressure coming out of the open end of the injection tube can be controlled. 2 and / or H 2The gas bubbles of S dissolve in water within a very short time and CO 2 and / or H 2 This ensures that S remains dissolved in the water prior to mineralization processes in the reservoir. 2 and / or H 2 The addition of S gas lowers the pH of the water, enhancing the dissolution of minerals in the reservoir and providing the cations necessary for the mineralization and removal of carbon and sulfur.

[0040] In one embodiment, the method comprises: 2 and / or H 2 estimating the mineralization potential of S, the estimating step including: The CO 2 and / or H 2 In addition to S, a tracer substance was dissolved in the water, and dissolved CO 2 and / or H 2 The concentrations of S and dissolved tracer material are 2 and / or H 2 be performed in a controllable manner so that the initial molar ratio of S to tracer substance is predetermined; The CO 2 and / or H 2 In response to the injection of S and a dissolved tracer material, the CO 2 and / or H 2 monitoring the molar ratio of S to the tracer material, said monitoring wells detecting dissolved CO 2 and / or H 2 The well is interconnected with the injection well via a flow path so that at least a portion of the injection water mixed with S and the tracer material flows to the monitoring well via the flow path. 2 and / or H 2 S and the concentration of the tracer substance are measured, and based on the measured concentration, the CO 2 and / or H 2 determining the molar ratio of S to said tracer material; and CO achieved by water-rock reactions 2 and / or H 2 The reduction index showing the amount of reduction in CO 2 and / or H 2 This is based on comparing the molar ratio of S to the tracer material with the corresponding molar ratio in the injection well at the confluence.

[0041] Based on such measurements, the geological reservoir in question is considered to be a reservoir of CO injected via an injection well. 2 and / or H 2 It is possible to determine whether the mineral has the capacity to store S in a mineralogic form.

[0042] CO 2 Regarding the above, the tracer substance is SF5CF3 tracer, SF 6 or rhodamine tracers (both of which are conservative tracers), or C-14 tracers which only track carbon. One or more of these tracers can be used simultaneously.

[0043] Similarly, by dissolving KI in pressurized water and using tracer substances such as iodide ions, it has been shown that geological systems such as Iceland produce H through water-rock reactions. 2 It is possible to determine whether the compound has the ability to mineralize S.

[0044] In one embodiment, the method further comprises the step of determining whether H 2 The method further includes performing a correction of the avoidance index to account for the oxidation of S, thereby making the estimation of the reduction potential more accurate. The correction is performed by analyzing the geothermal water from the injection well for other types of sulfur and calculating the oxidation of H 2 Compare with the value obtained before injecting S and H 2 Before calculating the reduction index of S, 2 Excess sulfur species (e.g., SO) formed by the oxidation of S 4 2- Or S 2 O 3 - ) to H2 This can be done by adding to the value of S.

[0045] In one embodiment, the interlink between the injection well and the monitoring well is a fracture in the geological reservoir.

[0046] In one embodiment, the method comprises: 2 or H 2 To further ensure that the S gas remains dissolved in the injected water, the method further includes providing a constriction at the open end of the injection tube to maintain high water pressure within the injection tube.

[0047] In a second aspect of the present invention, CO 2 and / or H 2 A system suitable for removing (reducing) S is provided, comprising: · Means for conveying water from the water source to the injection well; CO 2 and / or H 2 A means for delivering S gas to the injection well; Water pressure is CO 2 and / or H 2 At a depth h1 ≥ 0 of the injection well, which is lower than the pressure of S, CO 2 and / or H 2 A means for dissolving S gas in water; CO in the water 2 and / or H 2 The CO due to the buoyancy of the S gas bubbles 2 and / or H 2 means for transporting said water stream from said depth h1≧0 to a greater depth h1+h2 (h1+h2>h1) at a downward flow rate that is greater than the upward flow rate of S gas bubbles; Dissolved CO 2 and H 2 means for maintaining the resulting pH value of said S-containing pressurized water stream at about 2 to 4, preferably about 2.5 to 3.5, more preferably about 3.2; and Dissolved CO 2 and / or H 2A method of injecting water containing S into the ground.

[0048] In one embodiment, CO 2 and / or H 2 The means for dissolving S gas in water is high pressure CO 2 and / or H 2 an injection pipe for directing S gas to an injection well, the injection pipe being configured such that the water pressure in the injection well at the open end of the injection pipe is such that the CO 2 and / or H 2 The injection well has an open end extending into the injection well at a depth h1≧0 selected to be less than the pressure of the CO S gas. 2 and / or H 2 By increasing the upward flow rate of the S gas bubbles, the CO 2 and / or H 2 and pump means capable of transporting the water to a depth of h1 or more without S escaping from the water.

[0049] In one embodiment, the system further comprises an outer tube surrounding said injection tube having an open end extending downwardly into said injection well at a depth h1+h2, and said pumping means is a water pump for pumping water into a space between the outer tube and the injection tube to pump dissolved CO 2 and / or H 2 The means for injecting S into the geological reservoir is characterized by the downward flow rate of water and the resulting flow rate created by pumping water into the space between the outer pipe and the injection pipe. 2 In situations where the 2 h1+h2 may be selected such that the pH value of the injected water containing is below a preset pH limit value.

[0050] In one embodiment, CO 2 and / or H 2 The means for dissolving S in water further comprises: CO 2 and / or H 2a sparger attached to the open end of the gas injection tube adapted to maximize the interfacial area between the gas and the water; or a CO 2 and / or H 2 S gas is mixed with water to produce CO 2 and / or H 2 To obtain a uniform mixture of S gas in the water, and to reduce the amount of CO remaining in the water 2 and / or H 2 a mixer adapted to dissolve bubbles of S gas; or CO 2 and / or H 2 a sparger attached to the open end of the injection tube adapted to maximize the interfacial area between the CO gas and the water; 2 and / or H 2 To obtain a uniform mixture of S and CO gases in the water, 2 and / or H 2 a mixer mounted within the outer tube between the sparger and the open end of the outer tube adapted to mix CO2 remaining in the water with S; 2 and / or H 2 Something that can dissolve the air bubbles in S.

[0051] Thus, a practical and cost-effective system for in situ mineral carbonation in reactive rocks, e.g., basalt, is provided in which dissolved CO2 at a concentration high enough to promote reaction with the reactive rock, e.g., basalt, is provided. 2 and / or H 2 Similarly, the low pH of the water promotes dissolution of minerals in geological reservoirs, thereby providing the cations necessary for carbon and sulfur mineralization and mitigation.

[0052] In the method according to the present invention, once dissolved CO 2 and / or H 2 Since S loses buoyancy, the risk of leakage is reduced and safety is improved dramatically.2 and / or H 2 Injecting S promotes carbonation of the host rock, and CO 2 and / or H 2 This will enable safe long-term underground storage of S.

[0053] It should be noted that according to the present invention, the term water means fresh water, water from geothermal power plants, brine, sea water, etc. The water source may therefore be any type of water. Similarly, CO 2 and / or H 2 S-gas may originate from any source, including conventional power plants, geothermal power plants, industrial production, and gas separation stations.

[0054] In general, the various aspects of the invention can be combined and combined in any manner possible within the scope of the invention. These and other aspects, features and / or advantages of the invention will be apparent from and elucidated with reference to the embodiments described hereinafter. [Brief description of the drawings]

[0055] BRIEF DESCRIPTION OF THE DRAWINGS Some embodiments of the invention will now be described, by way of example only, with reference to the drawings in which: [Figure 1] FIG. 1 is a flow chart of a method for reducing CO2 and / or H2S in a geological reservoir in accordance with the present invention. [Diagram 2] Figure 2 shows a schematic of the interaction between host rock and formation fluids during in situ storage of CO2 ore. [Diagram 3] FIG. 3 is a flow chart illustrating one embodiment of a method according to the present invention, showing in more detail how dissolved CO2 and / or H2S are injected into the reservoir. [Figure 4] FIG. 4 is a system according to the present invention for storing carbon dioxide (CO2) in a geological reservoir. [Diagram 5]FIG. 5 is a flow chart of one embodiment of a method for removing hydrogen sulfide (H2S) from a geological reservoir in accordance with the present invention. [Figure 6] FIG. 6 is a schematic representation of a method according to the present invention showing an injection well into which water is continuously injected. [Figure 7] FIG. 7 shows the relationship between the downward flow velocity of water (m / s) into the injection well and the diameter of spherical (top line) and elongated (bottom line) gas bubbles when buoyancy and downward drag are balanced for a given temperature, pressure and gas and water composition. The shaded area represents bubbles intermediate between spherical and elongated. As is evident from this figure, a means capable of generating small bubbles can be operated at relatively low flow velocities, e.g. 0.4 m / s or less, to provide a method or system according to the invention (i.e. at least balanced), whereas a means limited to large bubbles requires a means capable of providing higher flow velocities, e.g. 0.8 m / s or more, to be able to provide a method or system according to the invention (i.e. balanced). [Figure 8] Figure 8 is an expanded view of the first quarter of Figure 7. [Figure 9] FIG. 9 illustrates different embodiments of a system for removing (reducing) hydrogen sulfide (H2S) and carbon dioxide (CO2) in a reservoir according to the present invention. [Figure 10] FIG. 10 is a diagram illustrating different embodiments of a system for removing (reducing) hydrogen sulfide (H2S) and carbon dioxide (CO2) in a reservoir according to the present invention. [Figure 11] FIG. 11 is a diagram illustrating different embodiments of a system for removing (reducing) hydrogen sulfide (H2S) and carbon dioxide (CO2) in a reservoir according to the present invention. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0056] Description of the embodiments Figure 1 shows the CO storage in a geological reservoir. 2 and / or H 21 is a flow chart of a method according to the invention for attenuating S. The term geological reservoir may be understood as fractures in hot rock that extend in directions other than upward and downward and provide flow paths for injected water from a well.

[0057] In a first step (S1) 101, water is pumped from a water source to an injection well. The water source may be, but is not limited to, geothermal water, brine, fresh water, or seawater. For simplicity, the term "water" will be used below. The temperature of the water may vary from a few degrees Celsius to several hundred degrees Celsius.

[0058] In the second step (S2) 103, the water pressure is increased to CO 2 and / or H 2 At the junction, the pressure of CO becomes lower than that of S. 2 and / or H 2 S gas is mixed with the water, but at the same time the water is transported downward at a rate relative to the time the gas was injected into the injection well, so that for a given portion of the water flow, the water pressure will increase to a level that will cause the CO 2 and / or H 2 Ensure that it is greater than the partial pressure of S.

[0059] In step (S3) 105, CO 2 and / or H 2 Water with dissolved S is injected into an underground reservoir.

[0060] In one embodiment, step (S2) 103 comprises 2 and / or H 2 The water pressure in the injection well at the open end of the injection tube is equal to the CO gas pressure in the injection tube. 2 and / or H 2 and directing the gas through an injection tube having an open end extending downward into the injection well at a depth h1≧0 selected to be less than the pressure of the S gas. 2 and / or H 2To allow S gas to flow into water at a depth h1≧0, and at the same time, to allow the CO 2 and / or H 2 By providing a downward flow rate of water that is higher than the upward flow rate of the S gas bubbles, 2 and / or H 2 This is to ensure that S does not escape from the water and that the water is transported to a depth greater than h1.

[0061] In a preferred embodiment, CO 2 is injected into the open end of the injection pipe. 2 The gas pressure is between 20-35 bar. This high pressure increases the pH value of the water containing dissolved CO. 2 is relatively low, and the CO 2 The water-rock reaction is promoted.

[0062] One of the key aspects of the present invention is that CO is dissolved in water prior to dispersion as a single-phase fluid in the pores of reactive rock. 2 (and / or H 2 The solution is to dissolve CO in water. 2 dissolves into carbonic acid (H 2 CO 3 ), which forms bicarbonate (HCO 3 ) and carbonic acid (CO 3 2- ) can be dissociated into [ka]

[0063] For example, in basalt, plagioclase ((Ca, Na)Al 1.70 S 2.30 O 8 ), olivine ((Mg, Fe) 2 SiO 4 ), pyroxene ((Ca, Mg, Fe) 2 SiO 3 ) is the most abundant major mineral, but basaltic glass is also common. When these minerals and glasses come into contact with the injected acidic fluids, dissolution reactions occur, removing Ca from the rock matrix. 2+, Mg 2+ , Fe 2+ The following reactions 2 to 5 show the dissolution of plagioclase, olivine, pyroxene, and basaltic glass, respectively. The composition of the basaltic glass in reaction 5 is that of Stapafell glass reported in the scientific literature by Oelkers and Gislason (Ref. 11). [ka]

[0064] CO 2 Or H 2 After S injection, the dissolution reactions 2 to 5 proceed underground, and protons (H + ) is consumed, causing the pH of the formation fluid to increase.

[0065] Figure 2 shows the CO 2 In situ CO after injection into injection well 2000 2 A schematic showing the interaction of host rock with formation fluids as ore sequestration occurs. A depth scale of 800 m or less is shown on the left side of Figure 2. Arrows 2005-2007 indicate the different directions of groundwater flow in the region and with distance from injection well 2000. At arrow 2005, the water adjacent to injection well 2000 is slightly acidic, and single-phase fluids may be entering the formation and leaching cations from the rock matrix. With increasing distance from injection well 2006, increased rock dissolution increases the pH of the water, and therefore the concentration of ions increases. Further away from the injection well, clays and zeolites compete with carbonates for dissolved cations, resulting in supersaturation and precipitation of minerals.

[0066] At a certain concentration, water becomes supersaturated with secondary minerals such as carbonates, which begin to precipitate via reaction 6. [ka]

[0067] Minerals that form carbonates include calcite (CaCO 3), dolomite (CaMg(CO 3 ) 2 ), Magnesite (MgCO 3 ), siderite (FeCO 3 ) have been proposed. Which of these carbonates is CO? 2 It is difficult to predict in advance whether and to what extent precipitation will actually occur in the subsurface upon injection, and other minerals such as clays, hydroxides, and zeolites may form as well, competing with reaction 6 for the dissolved cations.

[0068] FIG. 3 is a flow chart of an embodiment of the method according to the invention, showing in more detail how said step (S3) 105 is performed.

[0069] In step (S3') 201, the water pressure of the water pumped from the water source is increased to form pressurized water. This can be done, for example, by sending water from the water source through a pipeline to an injection well, where the pressure in the pipeline is controlled to increase the pressure and the dissolved CO 2 and / or H 2 The pressure of the S gas can be adjusted by increasing it via a suitable device, such as a water pump.

[0070] In step (S3'') 203, CO 2 and / or H 2 S gas is dissolved in pressurized water, and the water pressure increases during the dissolution of the gas. 2 and / or H 2 The water pressure is selected to be lower than the pressure of the S gas in one embodiment. 2 and / or H 2 The pressure is somewhat lower than that of the S gas. In this embodiment, the dissolved H 2Said step (S3) 105 of injecting S into the geological reservoir is performed via an injection tube having an open end extending downwards into the injection well at a depth h1 ≥ 0 below the surface level of the water in the injection well. This depth is preferably chosen so that the water in the injection well, where the open end of the injection tube is located, has a low water pressure, but at a somewhat greater depth h2 reached as the water flows downwards, the dissolved CO 2 and / or H 2 This is chosen to be greater than the pressure of CO 2 Or H 2 When the S-dissolved water comes out of the open end of the injection tube, the surrounding pressure increases and the CO 2 Or H 2 This is to make the pressure of CO greater than the dissolution pressure of S. 2 Or H 2 With S dissolved, CO 2 Or H 2 Dissolved CO until the S mineralization water-rock reaction begins 2 Or H 2 S. At the same time, dissolved CO 2 and / or H 2 The low pH of S-bearing waters promotes dissolution of reservoir minerals, thereby providing the cations necessary for the mineralization and removal of carbon and sulfur. This gas dissolution process is driven by H 2 Use appropriate equipment to maximize the interfacial area between the S gas and water, and 2 Dissolved H to mix S uniformly in water 2 Mixing S into water and H remaining in the water 2 This can be easily achieved by dissolving the S gas bubbles.

[0071] In one embodiment, CO 2 and / or H 2 The step (S3) 105 of dissolving S gas in water is carried out by increasing the water pressure in the injection well at the open end of the injection tube to dissolve the CO 2 and / or H 2 CO is injected through an injection tube having an open end extending downward into the injection well at a depth h1≧0 selected to be less than the pressure of S gas.2 and / or H 2 Preferably, the water pressure is applied to the CO 2 gas in the piping at the open end. 2 and / or H 2 S gas pressure is slightly lower than that of CO 2 and / or H 2 Secondly, the S gas must enter the water at a depth h1 ≥ 0, travel some distance downward with the water flow, and then be forced to move downward under the water pressure at the greater depth h1 + h2 (i.e., CO 2 and / or H 2 This is to ensure that the water pressure after the gas is injected is sufficient. 2 and / or H 2 After S has traveled a distance h2 downward, the water pressure is 2 and / or H 2 S. This injection tube is used to extract CO from, for example, geothermal gas. 2 Or H 2 This is a tube that runs from a gas separation station that separates the S gas, which is then led via a pipeline to an injection well.

[0072] Figure 4 shows carbon dioxide CO 2 2 illustrates an embodiment of a system 200 according to the present invention for storing CO in a geological reservoir 201. 2 It is composed of a gas pipeline 202, a wellhead 209, a water inlet 203, a gas injection pipe 206, a sparger 207, a mixer 208, and an external water injection pipe 204. 2 is discharged at high pressure to a wellhead 209 and discharged to an injection well 210 via a gas injection pipe 206 having an open end at a depth h1≧0, which is surrounded by an external water injection pipe 204 having an open end located at a depth h1+h2. In this embodiment, the amount of water (liters / second) pumped to the injection well 210 is controlled via a valve 211, and water is pumped into the space between the injection pipe 206 and the external water pipe 205.

[0073] The depth of the opening of the injection pipe at depth h1 ≥ 0 is the water pressure at this depth that causes the CO 2 The pressure should be chosen to be slightly less than the pressure of the CO 2 This is to allow the gas to enter the water. 2 Further below the gas injection, that is, at depth h1+△h(△h< 2 The pressure of dissolved CO is greater than 2 CO 2 This is to ensure that the cations remain dissolved in water.

[0074] The flow rate of water into the space between the inlet tube 206 and the outer tube 204 is indicated by an arrow, and is calculated based on the flow rate of CO 2 CO due to gas buoyancy 2 It is chosen to be greater than the rising speed of the gas bubbles. 2 As the gas bubbles move downward, the water pressure increases and CO 2 When the bubbles are small, they rise slower and their surface area increases, which increases the dissolution rate, making them a favorable condition.

[0075] ​One way to analyze the required water flow velocity in the injection tube to prevent the spherical gas bubble from rising up the tube is to calculate when the buoyancy of a gas bubble (perfectly spherical shape) with the density of a carbon dioxide bubble at the relevant pressure and temperature is equal to the drag force at the downward flow velocity of the water. In this condition, the spherical gas bubble is stationary. If the flow velocity is small, the bubble moves upwards, if the flow velocity is large, the bubble moves downwards with the water flow. The calculation results are shown in Figures 7 and 8. The horizontal axis shows the downward flow velocity of the water (m / s), and the vertical axis shows the diameter of the bubble (mm). Since the bubble is not a solid sphere, it can deform into a flattened sphere in a flowing medium. This is especially the case for large bubbles, while small bubbles are kept spherical by surface tension. Methods and systems for handling relatively small bubbles, e.g., bubbles with a diameter of 6 mm or less, according to the present invention can be operated at relatively low flow velocities, e.g., 0.4 m / s or less, while methods and systems for handling relatively large bubbles, e.g., bubbles with a diameter of 20 mm or more, according to the present invention can be operated at relatively high flow velocities, e.g., 0.8 m / s or more.

[0076] Referring to FIG. 4, the sparger 207 is 2 It is placed at the open end of the injection tube 206 to maximize the interfacial area between the gas and the water. 2 The gas bubbles are evenly distributed in the water and the average bubble diameter is reduced, resulting in a reduction in the CO 2 The interfacial area between the metal and the water is maximized.

[0077] Below the sparger is a mixer 208, whose function is to mix the dissolved CO 2 Mix the water evenly and remove any CO remaining in the water. 2 The solution is to dissolve the gas bubbles, which creates more turbulence and reduces the amount of CO 2 This further promotes the dissolution of gases. 2 The gas bubbles break down into smaller bubbles, causing CO 2 This will increase the dissolution rate of the compound.

[0078] In one embodiment, the depth h1 of the water column in the outer tube is about 250 m, meaning that the water pressure is 24.5 bar. 2 This means that the pressure of the gas is slightly greater than 24.5 bar. 2 As the gas leaves the opening of the injection tube 206 and passes through the sparger 207, it quickly disperses into small bubbles and then dissolves in the water. The constant water flow in the space between the injection tube and the outer tube 204 creates a vertical downward velocity that dissolves the dissolved CO 2 moves towards the open end of the injection tube at said depth h1+h2. This depth is preferably 2 The pH value of CO is selected to be about 3.2. 2 It decreases with increasing pressure. This corresponds to when h1 + h2 ≈ 520 m. Dissolved CO leaves system 200 and enters the basalt 2 Containment of CO in 2 It is at this depth that dissolution begins. Also, the lower the pH value, the higher the rate of dissolution within the basalt.

[0079] An additional advantage of the present invention is its lower cost compared to conventional technologies. The overall "on-site cost" of capturing, transporting and storing this mixed gas at the CarbFix2 Hellisheioi site is estimated at US$24.8 / CO2 of mixed gas. 2 / H 2 S tonnes, which is the same price reported by others (US$35-143 / tonne CO 2 ) (Ref.12: Global CCS Institute; Ref.13: Rubin et al.; Ref.14: HU and Zhai, Ref.16: Sigfusson et al.; Ref.17: Gunnarsson et al.). This work demonstrates the efficiency and cost advantages of capturing mixed dissolved gas streams and storing them in deep geological sites.

[0080] While the invention has been illustrated and described in detail in the drawings and the foregoing description, such illustration and description are to be considered as illustrative or exemplary and not restrictive, and the invention is not limited to the disclosed embodiments. Other variations to the disclosed embodiments can be understood and effected by those skilled in the art in practicing the claimed invention, from a study of the drawings, the disclosure, and the appended claims.

[0081] Referring to the accompanying drawings, the present invention relates to a method for producing carbon dioxide (CO 2 ) and / or hydrogen sulfide (H 2 This paper is concerned with methods for reducing the number of Pumping or transferring water from a water source into an outer pipe (205) of an injection well (210) to create a pressurized water flow within said outer pipe (205); CO to the gas injection pipe (206) of the injection well (210) 2 and / or H 2 By injecting S-rich gas, pressurized CO 2 and / or pressurized H 2 Including CO 2 and / or H 2 generating an S-rich gas stream; The water pressure p(W) of the water in the outer tube (205) is 2 and / or H 2 At a depth h1≧0 that is lower than the pressure p(C) and / or p(H) of S, the pressurized water flow and the CO 2 and / or H 2 The CO 2 and / or H 2 dissolving substantially all of the pressurized water gas of the pressurized water stream into the pressurized water stream of S-rich gas; The water flow is adjusted from the depth h1≧0 to a depth h1+h2 ((h1+h2)>h1), and the CO 2 and / or H 2 The CO due to the buoyancy of the S gas bubbles 2and / or H 2 The dissolved CO in the water stream is dissolved in the water by transporting S gas at a downward flow rate v(W) that is higher than the upward flow rates v(C) and / or v(H). 2 and / or H 2 keeping S in solution; Dissolved CO 2 and / or H 2 injecting the pressurized water stream containing S into a reservoir of reactive rock at h1+h2 or a depth >(h1+h2).

[0082] In a particularly preferred embodiment of the method according to the invention, the geological reservoir is a geothermal reservoir.

[0083] In a particularly preferred embodiment of the method according to the invention, at the junction at depth h1, the injection pipe (206) is equipped with a means for sparging (207) to prevent CO dissolved in the water stream. 2 and / or H 2 The interfacial area between S increases.

[0084] In a further particularly preferred embodiment of the method according to the invention, said depth h1 is about 250-750 m, such as 250-600 m or 400-750 m, for example 300-600 m or 500-750 m.

[0085] In a further particularly preferred embodiment of the method according to the present invention, the downward flow velocity v(W) of the water is 0.5-1 m / s, such as 0.6-0.9 m / s, for example 0.65-0.85 m / s, for example 0.7 m / s.

[0086] In a further particularly preferred embodiment of the method according to the invention, the injection pipe (206) extends downwards inside the outer pipe (205) constituting the pressurized water flow and has an open end at the depth h1≧0.

[0087] In a further particularly preferred embodiment of the method according to the invention, said outer pipe (205) constituting said pressurized water flow has an open end at said depth h1+h2.

[0088] In a further particularly preferred embodiment of the method according to the invention, the CO 2 pressure, p(CO 2 ) is about 15 to 40 bar, for example 17 to 38 bar, for example 20 to 36 bar, preferably about 22 to 34 bar, more preferably about 24 to 32 bar, most preferably about 24.5.

[0089] In a further particularly preferred embodiment of the method according to the invention, H at a junction with a depth h1≧0 2 The pressure (pH) of S is about 3 to 9 bar, such as 4 to 8 bar, preferably about 5 to 7 bar, more preferably about 5.5 to 6.5 bar, such as 5.6 to 6.4, such as 5.7 to 6.3 bar, most preferably about 6 bar.

[0090] In a further particularly preferred embodiment of the method according to the invention, the dissolved CO 2 and / or H 2 The resulting pH value of the pressurized water stream containing S is between about 1 and 5, such as between about 2 and 4, preferably between about 2.5 and 3.5, such as between about 2.6 and 3.4, more preferably between about 2.7 and 3.3, such as between about 3.2.

[0091] In yet another particularly preferred embodiment of the method according to the invention, the method further comprises the following steps: The dissolved CO 2 and / or H 2 dissolving a tracer substance in a predetermined molar ratio compared to S; - providing a monitoring well (610) interconnected with the outer tube (205) of the injection well (210 / 612) via a flow passage (614), thereby detecting the dissolved CO 2 and / or H 2at least a portion of the pressurized water mixed with S and the tracer material flows from the outer pipe (205) of the injection well (210 / 612) through the flow path (614) to the monitoring well (610); CO in the monitoring well (610) 2 and / or H 2 and measuring the concentrations of S and the tracer substance, and based thereon, measuring the CO concentration in the monitoring well (610). 2 and / or H 2 Establishing the molar ratio of S to the tracer substance; and CO in the monitoring well (610) 2 and / or H 2 and comparing the molar ratio of S to the tracer material to the predetermined molar ratio in the pressurized water stream at the depth h1 of the outer tube (205) of the injection well (210 / 612). 2 and / or H 2 To determine a reduction index that indicates the degree of reduction of S.

[0092] With reference to the accompanying drawings, the present invention further relates to a method for producing a carbon dioxide (CO 2 ) and / or hydrogen sulfide (H 2 The present invention relates to a system for removing a suction pipe (S) comprising: · Injection wells (210); an outer tube (205) extending downwardly within said injection well (210); an injection pipe (206) extending downwardly within said injection well (210); · means for pumping or transferring water from a water source into said outer pipe (205) thereby creating a pressurized water flow within said outer pipe (205); CO 2 and / or H 2 S-rich gas is fed into the injection tube (206), thereby producing pressurized CO 2 , and / or pressurized H 2 Including CO 2 and / or H 2 means for producing an S-rich gas stream; The water pressure p(W) of the water in the outer tube (205) is 2 and / or H 2 At a depth h1≧0 that is lower than the pressure p(C) and / or p(H) of S, the pressurized water flow and the CO 2 and / or H 2 means for combining the S-rich gas streams; The water flow is moved from the depth h1≧0 to a depth h1+h2 where (h1+h2)>h1, and the CO 2 and / or H 2 The CO due to the buoyancy of the S gas bubbles 2 and / or H 2 a means for transporting S gas at a downward flow velocity v(W) greater than the upward flow velocities v(C) and / or v(H); Dissolved CO 2 and H 2 means for maintaining a resultant pH value of said pressurized water stream containing S at about 2 to 4, preferably about 2.5 to 3.5, more preferably about 3.2; Dissolved CO 2 and / or H 2 Means for injecting said pressurized water stream containing S into a reservoir of reactive rock at h1+h2 or a depth >(h1+h2).

[0093] In a particular preferred embodiment of the system according to the invention, the system further comprises means for sparging (207) attached to said injection pipe (206) at the junction at a depth h1≧0.

[0094] In a further particularly preferred embodiment of the system according to the invention, said depth h1≧0 is about 250-750 m, such as 250-600 m or 400-750 m, for example 300-600 m or 500-750 m.

[0095] In a further particularly preferred embodiment of the system according to the invention, said means for transferring said water flow from said depth h1 to a depth h1+h2 ((h1+h2)>h1) are capable of causing a downward flow velocity v(W) of said water to be between 0.5 and 1 m / s, such as between 0.6 and 0.9 m / s, for example between 0.65 and 0.85 m / s, such as 0.7 m / s.

[0096] In a further particularly preferred embodiment of the system according to the invention, said injection tube (206) extends downwards into said outer pipe (205) and has an open end at said depth h1≧0.

[0097] In a further particularly preferred embodiment of the system according to the invention, said outer pipe (205) has an open end at said depth h1+h2.

[0098] In yet another particularly preferred embodiment of the system according to the invention, the system further comprises: The dissolved CO 2 and / or H 2 means for dissolving a tracer substance in a predetermined molar ratio relative to S; ·Monitoring wells (610); Dissolved CO 2 and / or H 2 a flow path (614) through which at least a portion of the pressurized water mixed with S and the tracer material flows from the outer pipe (205) of the injection well (210 / 612) to the monitoring well (610); CO in the monitoring well (610) 2 and / or H 2 and measuring the concentrations of S and the tracer substance, and based thereon, measuring the CO concentration in the monitoring well (610). 2 and / or H 2 A means of establishing the molar ratio of S to tracer substance; CO in the monitoring well (610) 2 and / or H 2and comparing the molar ratio of S to the tracer material to the predetermined molar ratio in the pressurized water stream at the depth h1 of the outer tube (205) of the injection well (210 / 612). 2 and / or H 2 and determining a reduction index indicative of the degree of reduction of S.

[0099] The method and system according to the present invention can be further illustrated by the following example.

[0100] Example 1: 0.07 kg / s of CO from a gas purification unit or gas separation station at a geothermal power plant 2 The gas comes in at an initial pressure of 30 bar. A pipe with an outside diameter (OD) of 40 mm is selected to transport the gas to the injection well, resulting in a pressure loss of 1.45 bar. With other pressure losses included, the pressure at the wellhead is assumed to be 28 bar. A pipe with an OD of 32 mm is selected for injection, resulting in a pressure loss of 0.41 bar, but gravity increases the pressure head at the junction by 1.1 bar, resulting in a pressure of 28.6 bar at the junction.

[0101] The injection pipe is a 75 mm outer diameter pipe, and a volumetric flow rate of water of 1.94 kg / s is required to dissolve the gaseous carbon dioxide. The pressure loss under these conditions is 0.51 bar / 100 m. The water column in the injection pipe is therefore about 13 m higher than the water level in the well, due to the pressure loss up to the junction. The location of the junction does not need to be changed because of this pressure increase. However, the water column in the pipe rises another 15 m due to the pressure drop in the pipe below the junction, so the junction must be raised accordingly. The water level is therefore about 28 m higher than the water level in the well. To obtain a pressure of 25 bar at the junction, the water level must be lowered 255 m below the pipe level or 227 m below the well level.

[0102] Under these conditions, the pressure loss at the junction can reach up to 3.6 bar. The downward flow velocity of the water at the junction is approximately 0.95 m / s. When the same procedure was performed with a lower water flow rate of 1.73 kg / s, the downward flow velocity at the junction was 0.85 m / s. However, at this flow rate, not all the air bubbles could descend efficiently, and the process had to be stopped. If the inner diameter of the water pipe at the junction is reduced, the water flow rate of 1.73 kg / s can still achieve a sufficient downward flow velocity to completely dissolve the air bubbles. This design can reduce the water demand of this gas removal method.

[0103] Example 2: In this example, the carbon dioxide partial pressure is chosen to be 25 bar downhole, which means saturation at 25 bar pressure, 36 g of CO at 17°C. 2 pr.kg of water. At this temperature and pressure, the volume of carbon dioxide is about 20 times the equivalent mass of water at atmospheric pressure. For the water to pull the gas downwards, the volume of the gas must not exceed the volume of the water, and preferably be much smaller. For the water to be able to pull the gas downwards in the pipe, it is desirable for the water pressure at the gas release point (junction) to be close to the saturation pressure of 25 bar. However, a lower pressure is possible if a sufficient amount of water is available. Some of the gas dissolves in the water, while the rest forms small bubbles that travel with the water down the pipe. As the water gets deeper, the pressure gets higher and the bubbles get smaller, and more of the gas dissolves in the water, until all the gas is dissolved.

[0104] Example 3: In this embodiment shown in Figure 10, a monitoring well 610 is interconnected with an injection well 612 via a flow channel 614, which may be, for example, a fracture in the geological reservoir. 2 The step of estimating is to estimate the mineralization potential of CO 2 This involves using one or more tracer substances to trace gas, water, or carbon. Thus, CO 2One or more types of tracer may be added via a suitable tracer source for tracing one or more of these such that the molar ratio between gas, or water, or carbon and the tracer substance(s) is predetermined, i.e. the molar ratio is pre-fixed. This can be done, for example, by adding CO 2 This means that only one tracer can be used to trace, such as only C, only water, or a combination of these. As an example, one can use one tracer to trace the dilution between the injected fluid and the surrounding water in the reservoir, and one tracer to trace the CO in the reservoir. 2 To characterize the advective and dispersive transport of saturated solutions, SF 5 CF 3 Tracer, SF 6 Tracer or rhodamine tracer can be implemented. Meanwhile, CO 2 The concentration of C-14 tracer injected with CO 2 - Estimate the mineralization of the injected CO when performing mass balance calculations, as it changes as a result of water-rock interactions 2 The dissolved CO 2 As a result of injection of CO 2 A monitoring device (not shown here) may be provided to monitor the molar ratio between gas, or water, or carbon, and the tracer substance(s). As already mentioned, the monitoring well 610 is connected to the injection well 612 via the flow path, and the dissolved CO 2 At least a portion of the injection water mixed with the tracer material flows into the monitoring well 610 through the flow path 614. By comparing the molar ratios in the monitoring well 610 and the injection well 612, the CO 2 Therefore, it is possible to obtain a reduction index that indicates the amount of SF 5 CF 3 Tracer, [SF 5 CF 3 ] / [CO 2 ] is 1 in the injection well 612 but 2 in the monitoring well 610, 2It can be clearly shown that half of the water has chemically reacted with the rocks via the water-rock reaction.

[0105] Such a monitoring well 610 may likewise be implemented in connection with the embodiment shown in FIG.

[0106] Example 4. FIG. 5 illustrates an embodiment of a method according to the present invention for removing hydrogen sulfide in a geothermal reservoir, where H 2 The mineralization potential of S is estimated. This method can be performed either prior to the method steps of FIG. 1 or as a monitoring method carried out at a later time.

[0107] In step (S4) 301, dissolved H 2 In addition to S, tracer substances such as KI can be controllably dissolved and H 2 The molar ratio of S to the tracer substance can be predetermined.

[0108] In step (S5) 303, dissolved H 2 In response to the injection of S and dissolved tracer material into the injection wells, H was observed in the monitoring wells. 2 The molar ratio of S to the tracer material is monitored. This is done by monitoring the dissolved H as the tracer material, which is connected to the injection well through channels such as cracks and fissures in the rock. 2 At least a part of the injected water containing S flows into the monitoring well through this flow path. 2 Measure the concentrations of S and tracer substances, and based on that, 2 This involves measuring the molar ratio of S to the tracer substance.

[0109] In step (S6) 305, H in the monitoring well 2 The molar ratios of S to tracer material were compared with the corresponding molar ratios in the injection well to determine the H 2 A reduction index is calculated to show the amount of reduction in H 2If the molar ratio of S to tracer material is 1.0, but 0.5 in the monitoring well, dissolved H 2 It has been shown that half of the S is mineralized in geothermal reservoirs by water-rock reactions. However, further improvements to this method require the use of H, which is a source of uncertainty. 2 It may be desirable to make a correction that takes into account the oxidation of S to other sulfur species.

[0110] Example 5: FIG. 6 is a schematic depiction of the method of FIG. 5 showing an injection well 400 into which water 409 is continuously injected. Such wells may have a total depth of several kilometers. As shown, the well is partially filled with water, with the water level 406 near the closure cap of the injection well casing 401. The continuous pumping of water creates a downward flow of water downhole, with some of the water flowing in the direction indicated by arrow 404 into the geothermal reservoir 403. As depicted, the injection well includes a casing 401, such as a steel pipe, that seals the well (e.g., from fresh groundwater above the geothermal reservoir). The height of such a casing 401 may vary from a few hundred meters to over 1000 meters. As shown, the remainder of the injection well is in rock 402. Water-rock reactions occurring in the geothermal reservoir can result in the dissolution of dissolved H in the rock. 2 Shown in the enlarged view of 404 is the flow path of S and dissolved H 2 S reacts with metal ions (Me)407 in rocks to form Me sulfides408. For example, if Me is Fe, the Me sulfide becomes Fe-sulfide.

[0111] The temperature of the water 409 pumped into the well is usually around 100°C when the water source is a geothermal well, but it is higher than that of hot water. 2 A lower temperature is preferable since less water is needed to dissolve the S. However, this depends on the water source, i.e. whether a fresh water source (cold water) is used instead of a geothermal water source.

[0112] Example 6: FIG. 9 shows the hydrogen sulfide (H 2 5 shows a schematic diagram of an embodiment of a system 500 according to the present invention for reducing H 2 S gas pipeline 502, wellhead 509, water inlet 503, injection pipe 506, sparger 507, mixer 508, outer pipe 504. 2 S is delivered at high pressure to a wellhead 509 and delivered to an injection well 510 via an injection pipe 506 having an open end at a depth h1≧0, surrounded by an outer pipe 504 having an open end located at a depth h1+h2. In this embodiment, the volumetric flow rate (in litres / sec) of water to the injection well 510 is controlled via a valve 511, which pumps water into the space between the injection pipe 506 and the outer pipe 505.

[0113] The depth of the opening of the injection pipe at depth h1 is the water pressure at this depth H 2 The pressure is chosen to be slightly less than the pressure of the H 2 This is to ensure that the S gas enters the water. Depth h1 + △h (where △h < 2 Below the injection point of S gas, the water pressure is 2 Greater than the internal pressure of S.

[0114] The flow of water into the space between the injection pipe 506 and the outer pipe 504 is H at the open end of the injection pipe. 2 The buoyancy force on the S gas causes the volumetric flow rate and hence velocity of the water (indicated by the arrow) to increase by H 2 The upward velocity of the H gas is chosen to be greater than that of the S gas. 2 As the S gas bubbles move downward, the water pressure increases and the bubbles become smaller, which reduces their upward velocity. Smaller bubbles are favorable conditions because they reduce the upward velocity of the bubbles and also increase the total surface area, which improves the dissolution rate.

[0115] In this embodiment, H 2 ​A sparger 507 is placed at the open end of the injection tube 506 to maximize the interfacial area between the S gas and the water. 2 The S gas bubbles are evenly dispersed in the water and the average diameter of the bubbles is reduced, 2 The interfacial area between the S gas and the water is maximized.

[0116] Below the sparger is a mixer 508. The role of the mixer is to mix the dissolved H 2 By mixing S with water, H 2 To obtain a uniform mixture of S gas in the water, the H gas remaining in the water is removed. 2 The goal is to dissolve the S gas bubbles, thus creating more turbulence and H 2 The dissolution rate of S gas is further improved. Also, the large H 2 The S gas bubbles break up into smaller gas bubbles, and H 2 This will increase the dissolution rate of S.

[0117] Example 7: Figure 10 shows the hydrogen sulfide (H 2 5 illustrates another embodiment of a system 600 according to the present invention for removing (reducing) H. In this embodiment, a monitoring well 610 is interconnected to an injection well 612 via a flow passage 614, which may be, for example, a fracture in the geothermal reservoir. This implementation of the monitoring well 610 may be implemented in the same manner as described above in connection with FIG. 5, except that the monitoring well 610 may be an injection well 612. 2 The purpose is to estimate the mineralization potential of S.

[0118] Example 8: Figure 11 shows the hydrogen sulfide (H 2Schematically shows yet another embodiment of a system 700 according to the invention for mitigating (reducing) hydrogen sulfide (S). In this embodiment, hydrogen sulfide is transported to an injection well 703 in another pipe 701 outside the water injection pipe 705. The pipe is fixed at the wellhead (not shown here), so the depth of the confluence cannot be changed even if conditions change, such as the water flow changes. Therefore, it is preferable to implement a pressure control valve 702 at the end of the injection pipe 705 to maintain a constant pressure at the confluence. The advantage of this solution is that the pressure loss in the injection pipe is lower, therefore a higher water flow rate can be maintained, making it easier to draw gas bubbles into the pipe.

[0119] Example 9 : Most of the security risks to storing carbon underground come from gaseous CO 2 This is due to the tendency of water to leak back to the surface, into the atmosphere, or into adjacent freshwater aquifers, which is particularly problematic when attempting to store it in porous geological formations.

[0120] The experiment was carried out at the geothermal power plant in Hellisheidi, Iceland. The rocks at the injection site at Hellisheidi are of ultramafic to basaltic composition and have high lateral and vertical permeabilities (300 m and 1700 × 10, respectively). -15 m 2 ), with an estimated porosity of 8.5%.

[0121] Using the apparatus shown in Figure 4, 2 and H 2 O 70 and 1940gs respectively -1 The target mass of CO was injected. 2 and H 2 O was released at a depth of 330-360 m. At this depth, CO 2 is a flowing H in the form of small bubbles. 2 O was released through a sparger. 2 and H 2The O mixture was discharged from the sparger into the underground rocks via a mixing tube extending to a depth of 540 m. Along the way (approximately 420 m), 2 A static mixer has been installed to help dissolve the CO2. Over the course of three months, approximately 175 tons of CO2 were dissolved. 2 and about 5,000 tons of H 2 O was injected underground.

[0122] CO during injection 2 The complete dissolution was confirmed by a digital downhole camera (CO 2 This was confirmed by sampling the high-pressure well water using a custom-built baler, indicating the absence of bubbles.

[0123] The image shows that there are no gas bubbles in the well water, and CO is present 1.5 m from the fluid outlet at 540 m. 2 is found to be completely dissolved.

[0124] Twelve well water samples were analyzed to measure total dissolved inorganic carbon, and six of the samples had in situ pH measurements. In all cases, the dissolved inorganic carbon concentration in the samples was determined by the CO 2 and H 2 The average concentration of O was within 5% of the measured value of 0.82±2% mol / kg based on the mass flow rate of O, and the pH of the solution was 3.89±0.1. 2 It was confirmed that the compound was completely dissolved during the injection.

[0125] Therefore, when injected underground in a dissolved state, CO 2 There is no bubble formation or buoyancy, making it much less likely to escape into the atmosphere (Ref.15: Gilfillan et al, 2009).

[0126] Example 10: In addition, the following parameters 2 / H 2 Experimental injections of S . [Table 0]

[0127] In this example, the carbon dioxide and hydrogen sulfide partial pressures were set to 18 bar and 6 bar downhole.

[0128] CO 2 The pH value of water containing dissolved CO 2 As pressure increases, the CO in the water 2 It decreases with increasing content. In one experiment, the water depth was selected so that the pH value was about 3.2, which corresponds to a depth of 520 m. As can be seen from the table above, the water descent speed in this example was about 0.7 m / s. As can be seen from the table above, the water descent speed in this example was about 0.7 m / s, and changing the water descent speed to about 0.3 m / s resulted in failure.

[0129] In the claims, the term "comprising" does not exclude other elements or steps, nor does the indefinite article "a" or "an" exclude a plurality. A single processor or other unit may fulfill the functions of several items recited in the claims. The mere fact that certain measures are recited in mutually different dependent claims does not indicate that a combination of these measures cannot be used to advantage. Moreover, reference signs in the claims are not to be interpreted as limiting the scope.

[0130] REFERENCES all of which are incorporated herein by reference in their entireties. [Table REF]

Claims

1. The method includes the steps of: ２ ) and / or hydrogen sulfide (H ２ How to reduce S: - pumping or transporting water from a water source into the outer pipe (205) of an injection well (210) to create a pressurized water flow within said outer pipe (205); CO in the injection tube (206) of the injection well (210) ２ and / or H ２ S-rich gas is fed into the injection tube (206) to produce pressurized CO ２ , and / or pressurized H ２ CO containing S ２ and / or H ２ generating an S-rich gas stream; The water pressure p (W) of the water in the outer tube (205) is ２ and / or H ２ S pressure (p(CO ２ ) and / or p(H ２ S)) at a depth h1≧0 lower than the pressure of the pressurized water flow and the CO ２ and / or H ２ The S-rich gas stream is combined with the CO ２ and / or H ２ The pressurized water stream of the S-rich gas stream is added to the pressurized CO ２ and / or H ２ dissolving substantially all of the S gas; The water flow is from the depth h1≧0 to a depth h1+h2 ((h1+h2)>h1), and the CO ２ and / or H ２ The CO caused by the buoyancy of the S gas bubbles ２ and / or H ２ The upward flow rate of S gas v (CO ２ ) and / or v (H ２ The dissolved CO in the water stream is transported at a downward flow rate v(W) higher than the ２ and / or H ２ maintaining a solution of S; The dissolved CO ２ and H ２ maintaining a resultant pH value of said pressurized water stream containing S at about 2 to 4, preferably about 2.5 to 3.5, and more preferably about 3.2; Dissolved CO ２ and / or H ２ injecting said pressurized water stream containing S into a geological reservoir containing reactive rocks at h1+h2 or at a depth > (h1+h2).

2. 2. The method of claim 1, wherein the geological reservoir is a geothermal reservoir.

3. At the junction at a depth h1≧0, a sparging means (207) is attached to the injection pipe (206) to remove CO dissolved in the water stream. ２ and / or H ２ 2. The method of claim 1, further comprising increasing the interfacial area between S.

4. 10. The method according to any of the preceding claims, characterized in that the injection pipe (206) extends downwards inside the outer pipe (205) containing the pressurized water flow and has an open end at the depth h1≧0.

5. 5. The method of claim 4, characterized in that the outer pipe (205) containing the pressurized water flow has an open end at the depth h1+h2.

6. CO at the confluence at depth h1 ２ Pressure p(CO ２ 2. The method according to any of the preceding claims, wherein the pressure in the pressure vessel is about 20-36 bar, preferably about 22-34 bar, more preferably about 24-32 bar, and most preferably about 24.5 bar.

7. H at the confluence at depth h1 ２ Pressure p of S (H ２ 2. The method according to any of the preceding claims, characterized in that S) is about 4-8 bar, preferably about 5-7 bar, more preferably about 5.5-6.5 bar, most preferably about 6 bar.

8. The method according to any of the preceding claims, further comprising the steps of: The dissolved CO in the pressurized water flow at the depth h1≧0 of the outer tube (205) in the injection well (210 / 612). ２ and / or H ２ dissolving a tracer substance in a predetermined molar ratio relative to S; Providing a monitoring well (610) interconnected to the outer tube (205) of the injection well (210 / 612) via a flow path (614), thereby monitoring the dissolved CO ２ and / or H ２ at least a portion of the pressurized water mixed with S and the tracer material flows from the outer pipe (205) of the injection well (210 / 612) through the flow path (614) to the monitoring well (610); CO in the monitoring well (610) ２ and / or H ２ and measuring the concentration of S and a tracer substance, and based on the results, measuring the CO concentration in the monitoring well (610). ２ and / or H ２ Establishing the molar ratio of S to the tracer substance; CO in the monitoring well (610) ２ and / or H ２ and comparing the molar ratio of S to the tracer material to the predetermined molar ratio in the pressurized water stream at the depth h1 of the outer tube (205) in the injection well (210 / 612). ２ and / or H ２ A reduction index indicating the degree of reduction of S is determined.

9. Carbon dioxide (CO ２ ) and / or hydrogen sulfide (H ２ A system for reducing - injection well (210); an outer tube (205) extending downwardly inside said injection well (210); an injection pipe (206) extending downwardly within said injection well (210); - means for pumping or transferring water from a water source into said outer pipe (205), thereby creating a pressurized water flow within said outer pipe (205); ・CO ２ and / or H ２ S-rich gas is pumped into the injection tube (206), thereby producing pressurized CO ２ , and / or pressurized H ２ CO ２ and / or H ２ means for producing a S-rich gas stream; The water pressure p (W) of the water in the outer tube (205) is ２ and / or H ２ S pressure (p(CO ２ ) and / or p(H ２ S)) at a depth h1≧0 lower than the pressure of the pressurized water flow and the CO ２ and / or H ２ means for combining said S-rich gas stream with said S-rich gas stream; A means for transporting the water flow from the depth h1≧0 to a depth h1+h2 ((h1+h2)>h1) at a downward flow velocity v(W), and at h1+h2, ２ Gas and / or H ２ The CO caused by the buoyancy of the S gas bubbles ２ Gas and / or H ２ The upward flow velocity of S gas v (CO ２ ) and / or v (H ２ S) higher than the means; The dissolved CO ２ and H ２ means for maintaining a resultant pH value of said pressurized water stream containing S at about 2 to 4, preferably about 2.5 to 3.5, more preferably about 3.2; Dissolved CO ２ and / or H ２ Means for injecting said pressurized water stream containing S into a geological reservoir containing reactive rock at h1+h2 or at a depth > (h1+h2).

10. 10. The system according to claim 9, further comprising a means for sparging (207) attached to the injection pipe (206) at the junction at a depth h1≧0.

11. 11. The system according to claim 9 or 10, characterized in that the injection pipe (206) extends downwards into the outer pipe (205) and has an open end at the depth h1≧0.

12. The system according to any one of claims 9 to 11, characterized in that the outer pipe (205) has an open end at the depth h1+h2.

13. The system of any one of claims 9 to 12, further comprising: The dissolved CO ２ and / or H ２ means for dissolving a tracer material in a predetermined molar ratio relative to S into said pressurized water flow at said depth h1 of said outer pipe (205) in said injection well (210 / 612); -Monitoring well (610); The dissolved CO ２ and / or H ２ a flow path (614) through which at least a portion of the pressurized water mixed with S and the tracer material flows from the outer pipe (205) of the injection well (210 / 612) to the monitoring well (610); CO in the monitoring well (610) ２ and / or H ２ and measuring the concentration of S and a tracer substance, and based on the results, measuring the CO concentration in the monitoring well (610). ２ and / or H ２ a means for establishing the molar ratio of S to the tracer material; CO in the monitoring well (610) ２ and / or H ２ and comparing the molar ratio of S to the tracer material to the predetermined molar ratio in the pressurized water stream at the depth h1 of the outer tube (205) of the injection well (210 / 612). ２ and / or H ２ A means for determining a reduction index indicative of the degree of reduction of S.

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