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 THE INVENTION The present invention relates to a method and system for reducing carbon dioxide (CO2) and hydrogen sulfide (H2S) by injecting them into a geological reservoir and then storing them. [Background technology]

[0002] Background of the Invention Carbon dioxide (CO2) and hydrogen sulfide (H2S) are gases that are released in large quantities during various industrial processes, such as the combustion of fossil fuels, and these two gases pose significant challenges to the environment.

[0003] Reducing industrial CO2 emissions is one of the major challenges of this century (Ref.1: Broecker and Kunzig). Geothermal sources generally emit relatively small amounts of CO2 and are classified as renewable energy sources, 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 by utilizing 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 naturally contains dissolved gases, including both greenhouse gases CO2 and hydrogen sulfide (H2S). These gases are by-products of geothermal energy production and are of magmatic origin. When a conventional geothermal power plant is operational, the gases in the steam are vented to the atmosphere.

[0005] Until now, geothermal power plants have been exempt from purchasing CO2 emission allowances because of their low greenhouse gas emissions, but as climate change policies become stricter, the price of CO2 emissions is expected to rise.

[0006] Hydrogen sulfide emissions from geothermal power plants are one of the environmental concerns associated with geothermal energy utilization. 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 of exposure. Low levels and prolonged exposure can cause eye irritation and irritation, while high levels and short-term exposure can cause dizziness, headaches, and nausea, and can be fatal if atmospheric concentrations of H2S exceed 300 ppm.

[0007] Concentrations of hydrogen sulfide in geothermal fluids typically range from a few ppb to several hundred ppm (Ref. 3 + 4: Arnorsson). When high-temperature geothermal fluids are utilized, 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 annually, without any countermeasures in place. Hydrogen sulfide is released above cooling towers to reduce the risk of high concentrations of hydrogen sulfide occurring near the power plant. The wind carries hydrogen sulfide away from the power plant site and, depending on the weather, can cause unpleasant odors in nearby communities.

[0008] To date, CO2 has been stored as a supercritical fluid in association 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 event, to reduce the amount of CO2 released into the atmosphere, whether from geothermal or other power plants, CO2 abatement in geological structures is an attractive, albeit relatively unexplored, possibility. The standard method for geological carbon storage and sequestration involves injecting CO2 as bulk into geological formations at depths of 800 meters or more. At this depth, CO2 is in a supercritical state and is buoyant relative to the host rock fluid. As a result, the buoyant CO2 can potentially be transported to shallower subsurface regions or back to the surface (Ref. 6: Hawkins; Ref. 7: Benson).

[0009] Gislason et al. (Ref. 8) describe a generalized method for capturing CO2, which is transported as a pressurized gas via a 3 km pipeline to a pilot injection site. The proposed method involves injecting CO2 with water and then flowing the injected CO2 further down the well, resulting in a single fluid phase entering the sequestration layer, according to the authors of this publication. Similarly, Sigfusson et al. (Ref. 16) describe injecting approximately 175 tonnes of CO2 dissolved in 5000 tonnes of water into porous rock 400–800 m below the surface (at a depth of approximately 350 m below the surface). They point out that even though large amounts of water are required to store CO2 in this manner, the dissolved CO2 is not buoyant, allowing it to be stored at shorter distances from the surface than supercritical CO2. Similarly, Gunnarson et al. (Ref. 17) describe the continuous injection of CO2 and H2S (dissolved in water at a depth of about 750 m below the surface) at temperatures of 200-260 °C into basalt rocks located about 2000 m below the surface, pointing out the fact that the great depth and high temperature allow for the injection of larger amounts of CO2 and H2S than would be possible if injected into shallower, cooler rock formations.

[0010] The methods detailed in these publications differ from those of the present invention. Consequently, none of these publications address the importance of the relationship between the downward velocity of the water flow and the ability to efficiently ensure that CO2 and / or HS released as bubbles of a predetermined size at the confluence point remain in solution at a predetermined depth / pressure. Thus, the publications are silent on the importance of transporting water, which is confluent with a CO2- and / or HS-rich gas stream, downward at a velocity greater than the upward velocity of the CO2 and / or HS gas bubbles dissolved in the water. In fact, quite the opposite (Ref. 16) merely points out the importance of dissolving carbon dioxide in water more generally during injection, mentioning only typical volumetric flow rates and mean residence times, and focusing on the importance of maintaining a constant water-to-CO2 mass ratio. This means that the factors affecting the usefulness of such methods were not fully understood by the authors at the time. Similarly, none of these publications address the relevant discovery of the present invention that water demand can be reduced simply by increasing the downward water flow rate. 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 (Ref. 9) review processes available for the reduction of H2S, for example in geothermal power plants. Most known methods involve the oxidation of H2S to elemental sulfur or 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 pose environmental problems.

[0012] Hibara et al. (Ref. 10) 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 effectiveness of such methods are not fully understood.

[0013] From the above, it can be seen that new, cost-effective, and environmentally friendly methods are needed to reduce CO2 and H2S emissions, whether from geothermal or other power plants. The inventors have discovered a new method to facilitate safe, permanent geological storage of CO2 and H2S. In this method, water demand can be significantly reduced by increasing the downward flow rate of water—for example, by simply reducing the diameter of the pipe surrounding the confluence of the CO2- and H2S-rich gas stream with the water. Thus, for a given confluence and a given flow rate of water, safe, long-term storage of CO2 and H2S can be facilitated simply by controlling the amount of CO2 and H2S gas dissolved in the injected water. Summary of the Invention [Problem to be solved by the invention]

[0014] Summary of the Invention As noted 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, there is provided a method for storing carbon dioxide (CO) and / or hydrogen sulfide (HS) in a geological reservoir, comprising: · Pumping (or otherwise transporting) water from the source to the injection well; dissolving CO2 and / or H2S gas in water by joining a CO2 and / or H2S rich gas stream with water under conditions where the hydraulic pressure of the water is lower than the partial pressure of CO2 and / or H2S in the CO2 and / or H2S rich gas stream; · ensuring retention of dissolved CO2 and / or H2S in the water by transporting water containing dissolved CO2 and / or H2S downward at a rate greater than the rate of rise of CO2 and / or H2S gas bubbles in the water; maintaining a resultant pH value of the pressurized water stream containing the dissolved CO and H S between about 2 and 4, preferably between about 2.5 and 3.5, and more preferably about 3.2; and Injection of water containing dissolved CO2 and / or H2S into geological reservoirs.

[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 should be understood as any kind of water, such as, for example, groundwater, sea / seawater, 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 (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, porous rock formations such as sandstone or limestone, or devices that put fluids into or under shallow soil layers.

[0019] In the context of the present invention, a gas stream rich in CO2 and / or H2S is understood to be a gas stream in which the relative content of CO2 and / or H2S is higher than the relative content of CO2 and / or H2S in the atmosphere.

[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 a hydraulic system when the fluid flows from a higher pressure to a lower pressure. Pressure is measured in SI units, the Pascal (Pa), or 1 Newton per square meter (1 N / 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, the term partial pressure or simply pressure of a gas (of CO and / or HS) should 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 that 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 at a given speed moves at a constant flow rate. This flow rate is given 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. Therefore, volumetric flow rate is equal to volume / time. On the other hand, mass flow rate represents 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 what is called a geothermal reservoir. 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 structures provide a flow path for the water injected from the well.

[0025] In the method and system of the present invention, the pressure of the dissolved CO2 and / or HS during the downward transport of water is less than the hydraulic pressure of the water (thereby keeping it in solution), so the CO2 and / or HS remain dissolved in the water, reducing the risk of leakage and significantly improving safety. The method of the present invention also allows for a significant reduction in water demand by increasing the downward flow rate of water. For example, the diameter of the pipe surrounding the confluence of the CO2- and / or HS-rich gas stream and the water can be simply reduced. CO2 injection promotes carbonization of the host rock, enabling safe, long-term underground storage of CO2. Thus, a method is provided for utilizing water-rock reactions occurring in naturally occurring reactive rocks in geothermal systems, such as basalt reservoirs, by injecting CO2 and / or HS into the reservoir geothermal system. This reduces the environmental impact of CO2 and HS gas emissions from geothermal power plants and other sources. Additionally, safe long-term storage of CO2 and H2S can be easily achieved by simply controlling how much CO2 or H2S gas is dissolved in the injected water at a given confluence and a given rate of water descent.

[0026] Furthermore, the reduction (removal) method of this invention is very economical and environmentally friendly, as there are no by-products that need to be disposed of. Returning CO2 and H2S to their original locations is considered an ideal method for reducing gas emissions from geothermal power plants, etc.

[0027] In the methods and systems of the present invention, as the water is transported downward, the gas pressure (i.e., partial pressure) of the dissolved CO2 and / or H2S is less than the hydraulic pressure of the water (thereby maintaining it in solution), so the gas remains dissolved in the water and does not degas from the water. In this manner, the methods of the present invention minimize the risk of gas bubbling out of the water, which would otherwise prevent the CO2 and / or H2S from being effectively transported to the geological reservoir where the gas is being absorbed and / or mineralized.

[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] Because the pressure of the CO2 and / or H2S before injection into the water is greater than the water pressure, gas bubbles will be present in the water at the confluence (i.e., 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 gas in water includes conducting CO2 and / or H2S gas through an injection tube having an open end extending downward into the injection well at a depth selected so that the hydraulic pressure of the water in the injection well at the open end of the injection tube is less than the pressure of the CO2 and / or H2S gas in the injection tube. Simultaneously, water is transported downward at a velocity relative to the time the gas is injected into the injection well, thereby ensuring that for a given portion of the water flow, the hydraulic pressure of the water is greater than the pressure of the dissolved CO2 and / or H2S relatively soon after the gas is injected into the water. In this way, the hydraulic pressure required to dissolve the CO2 and / or H2S gas in the water and to keep the CO2 and / or H2S gas dissolved in the water is obtained by transporting the water and gas to the appropriate depth, so that no external energy is required at or below the confluence to achieve or maintain the required hydraulic pressure. Furthermore, the method of the present invention ensures that when CO2 and / or HS are injected into the injection well (which is possible because the water pressure in the injection pipe is greater than the water pressure in the injection well), they do not begin to "fizz" at the open end after injection, but instead remain dissolved, i.e., in solution, for the time frame required for the CO2 and / or HS mineralization water-rock reaction to occur. This is similar to avoiding the scenario in which carbon dioxide begins to fizz when a carbonated beverage bottle is opened, resulting in the release of carbon dioxide from the bottle into the atmosphere. In this way, carbon dioxide fizzing does not occur if the bottle is opened under ambient pressure equal to or greater than the pressure within the bottle. The method of the present invention further ensures that the low pH of the water, due to the presence of dissolved CO2 and / or HS therein, can promote the dissolution of minerals in the geological reservoir, thereby providing the cations necessary for carbon and sulfur mineralization and mitigation.

[0031] In one embodiment, dissolving CO2 and / or H2S gas in water includes conducting CO2 and / or H2S 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 positioned at a depth greater than the open end of the injection tube, and the water being pumped into a space between the outer tube and the injection tube, the depth of the injection tube opening in the outer tube being selected so that the water pressure within the outer tube at the injection tube opening is less than the pressure of the CO2 and / or H2S gas within the injection tube, while transporting water downward at a velocity relative to the time the gas is injected into the injection well to ensure that, for a given portion of the water flow, the water pressure is greater than the sum of the partial pressures of the dissolved CO2 and / or H2S relatively soon after the gas is injected into the water.

[0032] In one embodiment, the water pumping rate and pipe diameter are selected so that the drag of the downward-flowing water on the injection well is greater than the buoyancy of the CO2 and / or H2S. A constant downward water flow is thus provided, ensuring that the dissolved CO2 and / or H2S moves downward toward the storage tank. A method or system for handling relatively small bubbles, e.g., bubbles 6 mm in diameter or less, according to the present invention requires a minimum water flow velocity of between 0.4 m / s and 1.4 m / s, depending on the dynamic forces in the system.

[0033] In one embodiment, the pressure of the CO2 gas at the open end of the injection tube (i.e., when the water pressure in the injection well is less than the CO2 gas pressure in the injection tube) is between 20 and 35 bar. At this pressure, the water temperature is between 20 and 40°C, resulting in a single fluid phase entering a reservoir, such as, but not limited to, a relatively fresh basaltic lava reservoir.

[0034] In one embodiment, the depth of the outer tube at the open end is selected so that the pH value of the injected water containing dissolved CO2 is between 2 and 4, preferably between 2.5 and 3.5, more preferably around 3.2. It is at this depth that the dissolved CO2 and / or H2S leave the outer tube and the sequestration of CO2 and H2S in the rock begins, i.e., the storage of carbon dioxide CO2 and hydrogen sulfide HS in the formation. The lower the pH value, the faster the rate of rock dissolution, and the lower the pH value will significantly enhance the sequestration of carbon dioxide CO2 and hydrogen sulfide HS in the reservoir (geological reservoir).

[0035] In one embodiment, the step of dissolving CO2 and / or H2S gas in the water further comprises mixing the dissolved CO2 and / or H2S with the water below the confluence, e.g., using a sparger and / or a mixer, to achieve a uniform mixture of CO2 and / or H2S gas in the water, thereby breaking down large bubbles and dissolving any remaining CO2 and / or H2S gas bubbles in the water. This creates turbulence in the mixture of CO2 and / or H2S gas and pressurized water, further facilitating dissolution of the CO2 and / or H2S gas below the confluence. Additionally, large CO2 and / or H2S bubbles are broken down into smaller bubbles, facilitating dissolution of the CO2 and / or H2S.

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

[0037] In embodiments, the step of dissolving CO2 gas in water further comprises maximizing the interfacial area between the CO2 gas and / or H2S gas and the water, which results in even dispersion of CO2 and / or H2S gas bubbles in the pressurized water, and furthermore, maximizing the interfacial area between the CO2 and / or H2S gas and the water reduces the average bubble diameter, which together significantly increase the rate of dissolution of CO2 and / or H2S into the pressurized water.

[0038] In an embodiment, the step of dissolving CO2 and / or H2S gas in the water further comprises mixing the dissolved CO2 and / or H2S with water to obtain a uniform mixture of CO2 and / or H2S gas in the water and dissolving any remaining CO2 and / or H2S gas bubbles in the water, which creates turbulence in the mixture of CO2 and / or H2S gas and pressurized water, further promoting the dissolution of CO2 and / or H2S gas. It also breaks up large CO2 and / or H2S gas bubbles into smaller bubbles, which improves the dissolution rate of CO2 and / or H2S.

[0039] In one embodiment, the step of dissolving CO2 and / or H2S gas in water includes conducting CO2 and / or H2S gas through an injection tube having an open end extending downward into the injection well at a depth selected so that the water pressure in the injection well at the open end of the injection tube is less than the pressure of the CO2 and / or H2S gas in the injection tube. At the same time, water is transported downward at a velocity relative to the time the gas was injected into the injection well to ensure that, for a given portion of the water flow, the water pressure is greater than the partial pressure of the dissolved CO2 and / or H2S relatively soon after the gas is injected into the water. The water pressure is slightly less than the gas pressure at the confluence depth so that, first, the CO2 and / or H2S gas can enter the injection well water at the confluence depth, and, second, after dissolving in the water and traveling downward at a predetermined downward velocity, the water pressure at that slightly greater depth is greater than the pressure of the CO2 and / or H2S. Therefore, by selecting the depth of the injection well confluence and the rate of water descent, it is ensured that the CO2 and / or H2S gas bubbles emerging from the open end of the injection tube dissolve in the water within a very short time and remain dissolved in the water prior to the mineralization process in the reservoir. At the same time, the addition of CO2 and / or H2S gas lowers the pH of the water, promoting 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 further comprises estimating the mineralization potential of CO and / or H S, the estimating step comprising: dissolving a tracer substance in the water in addition to the CO2 and / or H2S, and the concentrations of the dissolved CO2 and / or H2S and the dissolved tracer substance are controlled in a manner such that the initial molar ratio of the CO2 and / or H2S to the tracer substance is predetermined; monitoring the molar ratio of the CO2 and / or H2S to the tracer substance at a monitoring well in response to injecting the CO2 and / or H2S and the dissolved tracer substance, the monitoring well being interconnected with the injection well via a flow path such that at least a portion of the injection water mixed with the dissolved CO2 and / or H2S and the tracer substance flows to the monitoring well via the flow path, the monitoring including measuring the concentrations of the CO2 and / or H2S and the tracer substance at the monitoring well and determining the molar ratio of the CO2 and / or H2S to the tracer substance based thereon; and Determining a reduction index indicative of the amount of CO2 and / or H2S reduction achieved by water-rock reactions, said determination being based on comparing the molar ratios of CO2 and / or H2S to the tracer material in the monitoring wells with the corresponding molar ratios in the injection wells at the confluence.

[0041] Based on such measurements, it can be determined whether the geological reservoir in question has the capacity to store, in mineralogical form, the CO2 and / or H2S injected via the injection well.

[0042] For CO2, the tracer substance may be, but is not limited to, an SF5CF3 tracer, an SF6 or rhodamine tracer (all of which are conservative tracers), or a C-14 tracer that tracks carbon only. One or more of these tracers may be used simultaneously.

[0043] Similarly, dissolving KI in pressurized water and using tracer substances such as iodide ions could determine whether geological systems such as Iceland have the capacity to mineralize H2S through water-rock reactions.

[0044] In one embodiment, the method further comprises correcting the abatement index to account for oxidation of HS by other sulfide species, thereby providing a more accurate estimate of abatement potential. The correction may involve analyzing other types of sulfur in the geothermal water from the injection well and comparing it to a value obtained before injecting HS, and adjusting for excess sulfur species (e.g., SO4) formed by oxidation of HS before calculating the abatement index for HS. 2- and S2O3 - ) to the value of H2S.

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

[0046] In one embodiment, the method further comprises providing a constriction at the open end of the injection tube to maintain a high water pressure within the injection tube to further ensure that the CO or H2S gas remains dissolved in the injected water.

[0047] In a second aspect of the present invention, there is provided a system suitable for removing (reducing) CO2 and / or H2S, comprising: · Means for pumping water from the water source to the injection well; · Means for delivering CO2 and / or H2S gas to the injection well; means for dissolving CO2 and / or H2S gas in water at a depth h1 ≥ 0 in the injection well where the water pressure is lower than the pressure of CO2 and / or H2S; means for transferring the water flow from the depth h1≧0 to a greater depth h1+h2 (h1+h2>h1) at a downward flow velocity that is higher than the upward flow velocity of the CO2 and / or H2S gas bubbles due to buoyancy forces acting on the CO2 and / or H2S gas bubbles in the water; means for maintaining the resulting pH value of said pressurized water stream containing said dissolved CO and H S at about 2 to 4, preferably about 2.5 to 3.5, more preferably about 3.2; and · Means for injecting water containing said dissolved CO2 and / or H2S into the ground.

[0048] In one embodiment, the means for dissolving CO2 and / or H2S gas in water comprises an injection pipe for conducting high-pressure CO2 and / or H2S gas to an injection well, the injection pipe having an open end extending into the injection well at a depth h1≧0 selected so that the water pressure in the injection well at the open end of the injection pipe is less than the pressure of the CO2 and / or H2S gas in the injection pipe, and pumping means for making the downward flow rate of water greater than the upward flow rate of the CO2 and / or H2S gas bubbles at depths equal to or greater than h1, thereby enabling the water to be transported to depths equal to or greater than h1 without the CO2 and / or H2S escaping from the water.

[0049] In one embodiment, the system further comprises an outer pipe surrounding the injection pipe having an open end extending downward into the injection well at a depth h1+h2, the pumping means being a water pump that pumps water into a space between the outer pipe and the injection pipe, and the means for injecting dissolved CO2 and / or H2S into the geological reservoir is a downward flow rate and resulting flow rate of water created by pumping water into the space between the outer pipe and the injection pipe. In gas-limited situations, h1+h2 may be selected so that the pH value of the injection water containing dissolved CO2 is below a preset pH limit.

[0050] In one embodiment, the means for dissolving CO and / or H S in water further comprises: a sparger attached to the open end of the gas injection tube adapted to maximize the interfacial area between the CO2 and / or H2S gas and the water; or a mixer mounted within the outer tube between the open end of the injection tube and the open end of the outer tube, adapted to mix CO2 and / or H2S gas with water to obtain a uniform mixture of CO2 and / or H2S gas in water and to dissolve any remaining CO2 and / or H2S gas bubbles in the water; or a sparger attached to the open end of the injection tube, the sparger being adapted to maximize the interfacial area between the CO2 and / or H2S gas and the water; and a mixer attached within the outer tube between the sparger and the open end of the outer tube, the mixer being adapted to mix the CO2 and / or H2S with the water so as to obtain a uniform mixture of the CO2 and / or H2S gas in the water, and capable of dissolving any CO2 and / or H2S bubbles remaining in the water.

[0051] Thus, a practical and cost-effective system for in situ mineral carbonation in reactive rocks, e.g., basalt, is provided. In this system, water with a high enough concentration of dissolved CO2 and / or H2S to promote reaction with the reactive rock, e.g., basalt, is injected. Similarly, the low pH of the water promotes dissolution of minerals in the geological reservoir, thereby providing the cations necessary for carbon and sulfur mineralization and mitigation.

[0052] In the method of the present invention, once dissolved, CO2 and / or H2S loses its buoyancy, reducing the risk of leakage and dramatically improving safety. Furthermore, injecting dissolved CO2 and / or H2S promotes carbonation of the host rock, enabling safe long-term underground storage of CO2 and / or H2S.

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

[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 explanation of the drawings]

[0055] BRIEF DESCRIPTION OF THE DRAWINGS Some embodiments of the present 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 according to the present invention. [Figure 2] Figure 2 shows a schematic of the interaction between host rock and formation fluids during in situ storage of CO2 ore. [Figure 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 a reservoir. [Figure 4] FIG. 4 is a system according to the present invention for storing carbon dioxide (CO2) in a geological reservoir. [Figure 5] FIG. 5 is a flow chart of one embodiment of a method according to the present invention for removing hydrogen sulfide (H2S) from a geological reservoir. [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]Figure 7 shows the relationship between the downward flow velocity (m / s) of water 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-water composition. The shaded area represents bubbles intermediate between spherical and elongated. As can be seen from this figure, a means capable of generating small bubbles can operate at relatively low flow velocities, e.g., 0.4 m / s or less, to provide a method or system according to the present 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 provide a method or system according to the present 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 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 11] FIG. 11 illustrates 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 INVENTION

[0056] Description of the embodiment 1 is a flow chart of a method according to the present invention for attenuating CO2 and / or H2S in a geological reservoir. The term geological reservoir may be understood as fractures in hot rock that expand in directions other than upward and downward and provide flow paths for injection water from a well.

[0057] In the 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 hereinafter. The temperature of the water may vary from a few degrees Celsius to several hundred degrees Celsius.

[0058] In a second step (S2) 103, CO2 and / or H2S gas is introduced into the water at a confluence point where the water pressure is lower than the pressure of the CO2 and / or H2S, while at the same time transporting the water downward at a relative velocity compared to the time the gas was injected into the injection well, thereby ensuring that for a given portion of the water flow, the water pressure is greater than the partial pressure of the CO2 and / or H2S relatively soon after the gas is injected into the water.

[0059] In step (S3) 105, the water with dissolved CO2 and / or H2S is injected into a geological reservoir.

[0060] In one embodiment, step (S2) 103 includes conducting the CO2 and / or H2S gas through an injection tube having an open end extending downward into the injection well at a depth h1≧0 selected such that the water pressure of the water in the injection well at the open end of the injection tube is less than the pressure of the CO2 and / or H2S gas in the injection tube. This is simply to allow the CO2 and / or H2S gas to enter the water at depth h1≧0, while at the same time ensuring that the water is transported to depths greater than h1 without the CO2 and / or H2S escaping from the water by providing a downward flow rate of the water that is higher than the upward flow rate of the CO2 and / or H2S gas bubbles at depths greater than h1.

[0061] In a preferred embodiment, the pressure of the CO2 gas at the open end of the injection pipe is between 20-35 bar. This high pressure results in a relatively low pH value of the water containing dissolved CO2, which promotes CO2-water-rock reactions in the geological reservoir.

[0062] One of the key aspects of this invention is the dissolution of CO2 (and / or H2S) in water before dispersing it as a single-phase fluid into the pore spaces of reactive rock. CO2 dissolves to form carbonic acid (H2CO3), which is converted into bicarbonate (HCO3) and carbonate (CO3) in the following manner: 2- ) can be dissociated into [ka]

[0063] For example, in basalt, plagioclase ((Ca, Na)Al 1.70 Si 2.30 O8), olivine ((Mg, Fe)2SiO4), and pyroxene ((Ca, Mg, Fe)2SiO3) are the most abundant major minerals, 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 basalt glass, respectively. The composition of the basalt glass in reaction 5 is that of Stapafell glass reported in the scientific literature by Oelkers and Gislason (Ref. 11). [ka]

[0064] After CO2 or H2S is injected, 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 a schematic of the interaction of host rock with formation fluids during in situ CO2 ore sequestration following CO2 injection into injection well 2000. The left side of Figure 2 shows a depth scale of up to 800 m. Arrows 2005-2007 indicate the direction of regional groundwater flow and its variation 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 water pH, resulting in increased ion concentrations. Further away from the injection well, clays and zeolites compete with carbonates for dissolved cations, leading to mineral supersaturation and precipitation.

[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 have been proposed to form carbonates include calcite (CaCO3), dolomite (CaMg(CO3)2), magnesite (MgCO3), and siderite (FeCO3). It is difficult to predict in advance which of these carbonates will actually precipitate underground during CO2 injection, and to what extent. Other minerals, such as clays, hydroxides, and zeolites, may also form and compete 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 pressure of the water pumped from said water source is increased to form pressurized water, which can be done, for example, by sending water from the water source to an injection well via a pipeline, the pressure in the pipeline being increased via a suitable device, for example, a water pump, such that the pressure is controlled and adjusted to the pressure of the CO2 and / or H2S gases to be dissolved.

[0070] In step (S3″) 203, CO and / or H S gas is dissolved in pressurized water, the water pressure being selected so that the water pressure is lower than the pressure of the CO and / or H S gas during gas dissolution. The water pressure, in one embodiment, is about 6 bar or slightly lower than the pressure of the CO and / or H S gas. In this embodiment, step (S3) 105 of injecting the dissolved H S into the geological reservoir is performed via an injection tube having an open end extending downward into the injection well at a depth h ≥ 0 below the surface level of the water in the injection well. This depth is preferably selected so that the water pressure in the injection well, where the open end of the injection tube is located, is low but is greater than the pressure of the dissolved CO and / or H S at the somewhat greater depth h reached by the water as it flows downward. This is so that when the water with dissolved CO and / or H S emerges from the open end of the injection tube, the ambient pressure will be greater than the dissolution pressure of the CO and / or H S. This allows the CO2 and H2S to remain dissolved long enough for the mineralization water-rock reactions of CO2 and H2S to begin. At the same time, the low pH of the water containing the dissolved CO2 and / or H2S promotes dissolution of reservoir minerals, thereby providing the cations necessary for carbon and sulfur mineralization and removal. This gas dissolution process can be facilitated by using appropriate equipment to maximize the interfacial area between the H2S gas and water, mixing the dissolved H2S into the water to uniformly mix the H2S in the water, and dissolving any remaining H2S gas bubbles in the water.

[0071] In one embodiment, the step (S3) 105 of dissolving CO2 and / or H2S gas in water comprises conducting CO2 and / or H2S gas through an injection pipe having an open end extending downward into the injection well at a depth h1≧0 selected so that the water pressure of the water in the injection well at the open end of the injection pipe is less than the pressure of the CO2 and / or H2S gas in the injection pipe. Preferably, the water pressure is slightly less than the pressure of the CO2 and / or H2S gas in the pipe at this open end. This is to first ensure that the CO2 and / or H2S gas enters the water in the injection well, and second ensure that the water pressure at a greater depth h1+h2 after entering the water at depth h1≧0 and traveling a certain distance downward with the water flow (i.e., the water pressure after the CO2 and / or H2S gas has been injected). The water pressure after the CO2 and / or H2S has traveled the downward distance h2 will be greater than the pressure of the CO2 and / or H2S dissolved in the water. This injection pipe is, for example, a pipe extending from a gas separation station that separates CO2 and H2S gases from geothermal gas, and then led to the injection well via a pipeline.

[0072] 4 illustrates one embodiment of a system 200 according to the present invention for storing carbon dioxide (CO2) in a geological reservoir 201. The system comprises a CO2 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. CO2 is delivered at high pressure to the wellhead 209 and then to an injection well 210 via the gas injection pipe 206, which has an open end at a depth h1≧0, surrounded by an external water injection pipe 204, which has an open end at a depth h1+h2. In this embodiment, the rate of water pumped to the injection well 210 (liters / second) is controlled via a valve 211, which pumps water 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 selected so that the water pressure at this depth is slightly smaller than the pressure of the CO2 gas in the injection pipe. This is to allow the CO2 gas to enter the water.

[0074] The water flow rate into the space between the injection tube 206 and the outer tube 204 is selected so that the water flow rate, indicated by the arrow, is greater than the rate at which CO2 gas bubbles rise due to the buoyancy of the CO2 gas at the open end of the injection tube. Therefore, as the CO2 gas bubbles move downward, the water pressure increases, causing the CO2 to dissolve in the water, resulting in smaller bubbles and a slower rate of rise. Smaller bubbles are preferable because they rise less quickly and have a larger surface area, which increases the rate of dissolution.

[0075] One way to analyze the water flow velocity required within the injection pipe to prevent spherical gas bubbles from rising up the pipe is to calculate when the buoyancy of a gas bubble (perfectly spherical) with the density of a carbon dioxide bubble at the relevant pressure and temperature is equal to the drag force of the water at the downward flow velocity. Under these conditions, the spherical gas bubble is stationary. If the flow velocity is low, the bubble will move upward; if the flow velocity is high, the bubble will move downward 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 bubble diameter (mm). Since bubbles are not solid spheres, they can deform into flattened spheres in a flowing medium. This is especially true for large bubbles; 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] 4, a sparger 207 is placed at the open end of the injection pipe 206 to maximize the interfacial area between the CO2 gas and the water. This allows the CO2 gas bubbles to be evenly dispersed in the water, further reducing the average bubble diameter and maximizing the interfacial area between the CO2 and the water.

[0077] Below the sparger is a mixer 208, whose role is to mix the dissolved CO2 with the water evenly and dissolve any CO2 gas bubbles remaining in the water. This creates more turbulence, which further promotes the dissolution of CO2 gas. It also breaks up large CO2 gas bubbles into smaller ones, which increases the dissolution rate of CO2.

[0078] In one embodiment, the depth h1 of the water column within the outer tube is approximately 250 m, meaning the water pressure is 24.5 bar. This means the CO2 gas pressure is slightly greater than 24.5 bar. As CO2 gas exits 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. A constant water flow in the space between the injection tube and the outer tube 204 creates a vertical downward velocity, moving the dissolved CO2 toward the open end of the injection tube at depth h1 + h2. This depth is preferably selected so that the pH value of the dissolved CO2 is approximately 3.2, but the pH value decreases with increasing CO2 pressure. This corresponds to when h1 + h2 ≈ 520 m. It is at this depth that the dissolved CO2 exits the system 200 and begins to trap CO2 in the basalt rock 2. Furthermore, the lower the pH value, the faster the dissolution rate within the basalt rock.

[0079] An additional benefit of this 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 $24.8 / ton of CO2 / H2S mixed gas, which is significantly lower than the prices reported by others ($35-$143 / ton CO2) (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 study demonstrates the efficiency and cost advantages of capturing mixed dissolved gas streams and storing them at deep geological sites.

[0080] While the invention has been illustrated and described in detail in the drawings and foregoing description, such illustration and description is to be considered 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 reducing carbon dioxide (CO2) and / or hydrogen sulfide (H2S), comprising the following steps: Pumping or transferring water from a water source into the outer pipe (205) of the injection well (210) to create a pressurized water flow within said outer pipe (205); injecting CO2 and / or H2S rich gas into a gas injection pipe (206) of an injection well (210) to generate a CO2 and / or H2S rich gas stream containing pressurized CO2 and / or pressurized H2 in said injection pipe (206); dissolving substantially all of the pressurized water gas of the pressurized water stream into the pressurized water stream of the CO2 and / or H2S rich gas stream by merging the pressurized water stream and the CO2 and / or H2S rich gas stream at a depth h1≧0 where the water pressure p(W) of the water in the outer tube (205) is lower than the pressures p(C) and / or p(H) of the CO2 and / or H2S in the injection tube (206); maintaining the dissolved CO2 and / or H2S in the water stream in solution by transporting the water stream from the depth h1≧0 to a depth h1+h2 ((h1+h2)>h1) at a downward flow velocity v(W) that is greater than the upward flow velocity v(C) and / or v(H) of the CO2 and / or H2S gas due to buoyancy forces on the CO2 and / or H2S gas bubbles in the water stream at the depth h1+h2; Injecting said pressurized water stream containing dissolved CO2 and / or H2S 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 means for sparging (207) to increase the interfacial area between the CO2 and / or H2S dissolved in the water streams.

[0084] In a further particularly preferred embodiment of the method according to the invention, said depth h1 is about 250 to 750 m, such as 250 to 600 m or 400 to 750 m, for example 300 to 600 m or 500 to 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 to 1 m / s, such as 0.6 to 0.9 m / s, for example 0.65 to 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 downward 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 pressure of CO2 at the junction at a depth h1≧0, p(CO2), is about 15-40 bar, such as 17-38 bar, for example 20-36 bar, preferably about 22-34 bar, more preferably about 24-32 bar, most preferably about 24.5 bar.

[0089] In a further particularly preferred embodiment of the method according to the invention, the pressure (pH) of the H2S at the junction at a depth h1≧0 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, for example 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 resulting pH value of said pressurized water stream containing said dissolved CO and / or H 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 3.2.

[0091] In yet another particularly preferred embodiment of the method according to the invention, the method further comprises the following steps: dissolving a tracer substance in a predetermined molar ratio relative to the dissolved CO2 and / or H2S in the pressurized water flow in the outer tube (205) in the injection well (210 / 612) at a depth h1≧0; - providing a monitoring well (610) interconnected with the outer pipe (205) of the injection well (210 / 612) via a flow path (614), whereby at least a portion of the pressurized water mixed with the dissolved CO2 and / or H2S and the tracer substance flows from the outer pipe (205) of the injection well (210 / 612) to the monitoring well (610) via the flow path (614); measuring the concentrations of CO2 and / or H2S and the tracer substance in the monitoring well (610) and, based thereon, establishing a molar ratio of CO2 and / or H2S to the tracer substance in the monitoring well (610); and Determining a reduction index indicating the degree of reduction of CO2 and / or H2S based on comparing the molar ratio of CO2 and / or H2S to the tracer substance in the monitoring well (610) with the predetermined molar ratio in the pressurized water flow at the depth h1 of the outer pipe (205) of the injection well (210 / 612).

[0092] With reference to the accompanying drawings, the present invention further relates to a system for removing carbon dioxide (CO2) and / or hydrogen sulfide (HS), comprising: · Injection wells (210); an outer pipe (205) extending downward inside the 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); means for feeding a CO2 and / or H2S rich gas into said injection pipe (206), thereby generating a CO2 and / or H2S rich gas stream containing pressurized CO2 and / or pressurized H2 in said injection pipe (206); means for merging the pressurized water stream and the CO2 and / or H2S-rich gas stream at a depth h1≧0 where the water pressure p(W) of the water in the outer pipe (205) is lower than the pressures p(C) and / or p(H) of the CO2 and / or H2S in the injection pipe (206); means for transporting the water flow from the depth h1≧0 to a depth h1+h2, where (h1+h2)>h1, at a downward flow velocity v(W) that is higher than the upward flow velocity v(C) and / or v(H) of the CO2 and / or H2S gas due to the buoyancy force acting on CO2 and / or H2S gas bubbles in the water flow at the depth h1+h2; means for maintaining the resulting pH value of said pressurized water stream containing dissolved CO2 and H2S at about 2 to 4, preferably about 2.5 to 3.5, more preferably about 3.2; means for injecting said pressurized water stream containing dissolved CO2 and / or H2S into a reservoir of reactive rock at h1+h2 or a depth > (h1+h2).

[0093] In a particularly 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, the means for transferring the water flow from the depth h1 to a depth h1+h2 ((h1+h2)>h1) are capable of causing the water to have a downward flow velocity v(W) of 0.5 to 1 m / s, such as 0.6 to 0.9 m / s, for example 0.65 to 0.85 m / s, for example 0.7 m / s.

[0096] In a further particularly preferred embodiment of the system according to the invention, said injection pipe (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: means for dissolving a tracer substance in a predetermined molar ratio relative to the dissolved CO2 and / or H2S in the pressurized water flow at a depth h1≧0 in the outer pipe (205) of the injection well (210 / 612); ·Monitoring wells (610); a flow path (614) through which at least a portion of the pressurized water mixed with the dissolved CO2 and / or H2S and the tracer material flows from the outer pipe (205) of the injection well (210 / 612) to the monitoring well (610); means for measuring the concentrations of CO2 and / or H2S and the tracer substance in said monitoring well (610) and, based thereon, establishing a molar ratio of CO2 and / or H2S to the tracer substance in said monitoring well (610); and means for determining a reduction index indicating the degree of reduction of CO2 and / or H2S based on comparing the molar ratio of CO2 and / or H2S to the tracer substance in the monitoring well (610) with the predetermined molar ratio in the pressurized water flow at the depth h1 of the outer pipe (205) of the injection well (210 / 612).

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

[0100] Example 1: 0.07 kg / s of CO2 enters from a gas purification unit or gas separation station at a geothermal power plant. The initial gas pressure is 30 bar. A 40 mm outer diameter (OD) pipe is selected to transport the gas to the injection well, resulting in a pressure drop of 1.45 bar. Including other pressure losses, the pressure at the wellhead is assumed to be 28 bar. A 32 mm OD pipe is selected for injection, resulting in a pressure drop 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 water flow rate 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. Therefore, the water column in the injection pipe will be approximately 13 m higher than the water level in the well due to the pressure loss up to the junction. This pressure increase does not require changing the location of the junction. However, the water column in the pipe will rise another 15 m due to the pressure drop in the pipe below the junction, so the junction must be raised accordingly. Therefore, the water level will be approximately 28 m higher than the water level in the well. To achieve 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 reaches a maximum of 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, forcing the process to be stopped. By reducing the inner diameter of the water pipe at the junction, a sufficient downward flow velocity could be achieved even with a water flow rate of 1.73 kg / s, allowing the air bubbles to be completely dissolved. This design reduces the water demand for this gas removal method.

[0103] Example 2: In this example, the carbon dioxide partial pressure is chosen to be 25 bar downhole. This implies saturation at 25 bar, or 36 g CO2 pr. kg of water at 17 °C. At this temperature and pressure, the volume of carbon dioxide is approximately 20 times the equivalent mass of water at atmospheric pressure. For the water to pull the gas downward, the gas volume must not exceed the volume of the water, and preferably be much smaller. For the water to be able to pull the gas downward in the pipe, the water pressure at the gas release point (confluence) should be close to the saturation pressure of 25 bar. However, a lower pressure is possible if sufficient water volume is available. Some of the gas dissolves in the water, while the remaining gas forms small bubbles that travel down the pipe with the water. As the water depth increases, the pressure increases, the bubbles become smaller, and the gas dissolves in the water until all the gas is dissolved.

[0104] Example 3: In this embodiment shown in FIG. 10, a monitoring well 610 is interconnected with an injection well 612 via a channel 614, which may be, for example, a fracture in the underground reservoir. The purpose of this monitoring well 610 is to estimate the mineralization potential of CO2. The estimating step involves using one or more tracer substances to track CO2 gas, water, or carbon. In this manner, one or more types of tracer may be added via an appropriate tracer source to track one or more of these so that the molar ratio between CO2 gas, water, or carbon and the tracer substance(s) is predetermined, i.e., the molar ratio is fixed in advance. This means that tracing can be performed using only one tracer, such as CO2 only, C only, water only, or a combination thereof. As an example, an SF5CF3 tracer, SF6 tracer, or rhodamine tracer can be implemented to track the dilution between the injected fluid and the surrounding water in the reservoir and to characterize the advective and dispersive transport of the CO2-saturated solution in the reservoir. On the other hand, the concentration of the C-14 tracer injected with CO2 changes as a result of CO2-water-rock interactions, allowing the mineralization degree of the injected CO2 to be estimated when performing mass balance calculations. A monitoring device (not shown here) may be provided to monitor the molar ratio between CO2 gas, water, or carbon and the tracer material(s) in the monitoring well 610 as a result of injecting the dissolved CO2. As already mentioned, the monitoring well 610 is connected to the injection well 612 via the flow path, and at least a portion of the injection water mixed with the dissolved CO2 and the tracer material flows into the monitoring well 610 via the flow path 614. By comparing the molar ratios in the monitoring well 610 and the injection well 612, a reduction index indicating the amount of CO2 stored due to water-rock interactions can be determined. Therefore, if the tracer used is an SF5CF3 tracer and the molar ratio of [SF5CF3] / [CO2] is 1 in the injection well 612 but 2 in the monitoring well 610, it can be clearly shown that half of the CO2 has chemically reacted with the rock through the water-rock reaction.

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

[0106] Example 4. Figure 5 illustrates one embodiment of a method according to the present invention for removing hydrogen sulfide in a geothermal reservoir, where the mineralization potential for H2S is estimated. This method can be performed either prior to the method steps of Figure 1 or as a monitoring method carried out at a later time.

[0107] In step (S4) 301, a tracer substance such as KI is controllably dissolved in addition to the dissolved H2S, and the molar ratio of H2S to the tracer substance can be predetermined.

[0108] In step (S5) 303, in response to the injection of dissolved H2S and the dissolved tracer material into the injection well, the molar ratio of H2S to the tracer material is monitored in a monitoring well. The monitoring well is connected to the injection well through a flow path such as a crack or fissure in the rock, and at least a portion of the injection water mixed with the dissolved H2S as the tracer material flows into the monitoring well through this flow path. This monitoring includes measuring the concentrations of H2S and the tracer material in the monitoring well and determining the molar ratio of H2S to the tracer material based on the measured concentrations.

[0109] In step (S6) 305, the molar ratio of H2S to tracer material in the monitoring well is compared with the corresponding molar ratio in the injection well to obtain a reduction index that indicates the amount of H2S reduction due to water-rock interaction. For example, if the molar ratio of H2S to tracer material in the injection well is 1.0 and that in the monitoring well is 0.5, this indicates that half of the dissolved H2S is mineralized in the geothermal reservoir through water-rock interaction. However, to further improve this method, it may be desirable to correct for the oxidation of H2S to other sulfur species, which is a source of uncertainty.

[0110] Example 5: FIG. 6 is a schematic representation of the method of FIG. 5 showing an injection well 400 into which water 409 is continuously injected. The total depth of such a well can be several kilometers. As shown, the well is partially filled with water, with the water surface 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 into the geothermal reservoir 403 in the direction indicated by arrow 404. 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 can vary from a few hundred meters to over 1,000 meters. As shown, the remainder of the injection well is within rock 402. The water-rock reactions that occur in geothermal reservoirs are illustrated in the close-up of 404, which shows the flow path of dissolved H2S in the rock. The dissolved H2S reacts with metal ions (Me)407 in the rock to form Me sulfides408. For example, if Me is Fe, the Me sulfides will be Fe-sulfides.

[0111] The temperature of the water 409 pumped into the well is usually around 100°C if the source is a geothermal well, but preferably lower, as less water is needed to dissolve the H2S than with hot water. However, this depends on the source, i.e., whether a freshwater source (cold water) is used instead of a geothermal water source.

[0112] Example 6: 9 illustrates a schematic diagram of one embodiment of a system 500 according to the present invention for reducing hydrogen sulfide (HS) in a geothermal reservoir 501. The system includes an HS gas pipeline 502, a wellhead 509, a water inlet 503, an injection pipe 506, a sparger 507, a mixer 508, and an outer pipe 504. HS is delivered at high pressure to the wellhead 509 and to an injection well 510 via an injection pipe 506 having an open end at a depth h1≧0, which is surrounded by an outer pipe 504 having an open end located at a depth h1+h2. In this embodiment, the volumetric flow rate (liters / second) of water to the injection well 510 is controlled via a valve 511, and water is pumped 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 selected so that the water pressure at this depth is slightly less than the pressure of the H2S gas in the injection pipe. This is to ensure that the H2S gas enters the water. Depth h1 + △h (where △h <

[0114] The flow of water into the space between the injection pipe 506 and the outer pipe 504 is selected so that the volumetric flow rate and therefore velocity of the water (indicated by the arrows) is greater than the upward velocity of the HS gas due to buoyancy forces on the HS gas at the open end of the injection pipe. Thus, as the HS gas bubbles move downward, the water pressure increases, causing them to become smaller, which in turn reduces their upward velocity. Smaller bubbles are favorable conditions because they reduce their upward velocity and also increase the total surface area, improving the dissolution rate.

[0115] In this embodiment, in order to maximize the interfacial area between the H2S gas and water, a sparger 507 is placed at the open end of the injection pipe 506. This allows the H2S gas bubbles to be evenly dispersed in the water, and further reduces the average diameter of the bubbles, thereby maximizing the interfacial area between the H2S gas and water.

[0116] ​Below the sparger is a mixer 508. The role of the mixer is to mix the dissolved H2S with water to obtain a uniform mixture of H2S gas in the water and dissolve the remaining H2S gas bubbles in the water. Therefore, more turbulence is generated, which further improves the dissolution rate of H2S gas. Also, large H2S gas bubbles are broken down into smaller gas bubbles, which improves the dissolution rate of H2S.

[0117] Example 7: Figure 10 illustrates another embodiment of a system 600 according to the present invention for removing (reducing) hydrogen sulfide (HS) in a geothermal reservoir. In this embodiment, a monitoring well 610 is interconnected to an injection well 612 via a flow channel 614, which may be, for example, a fracture in the geothermal reservoir. The implementation of this monitoring well 610 is for estimating the HS mineralization potential, as described above in connection with Figure 5.

[0118] Example 8: FIG. 11 diagrammatically illustrates yet another embodiment of a system 700 according to the present invention for mitigating (reducing) hydrogen sulfide (HS) in a geothermal reservoir. In this embodiment, the hydrogen sulfide is transported to an injection well 703 in a separate pipe 701 outside the water injection pipe 705. Because the pipe is fixed at the wellhead (not shown here), the depth of the confluence cannot be changed even if conditions, such as changes in water flow, change. Therefore, a pressure control valve 702 is preferably implemented 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 low, thus allowing a higher water flow rate to be maintained and making it easier to draw gas bubbles into the pipe.

[0119] Example 9 : Much of the security risk associated with storing carbon underground comes from the tendency of gaseous CO2 to return to the surface and leak into the atmosphere or adjacent freshwater aquifers, which is particularly problematic when attempting to store carbon in porous geological formations.

[0120] The experiment was conducted at the geothermal power plant in Hellisheidi, Iceland. The rocks at the injection site at Hellisheidi are ultramafic to basaltic in composition and have high permeability both laterally and vertically (300 m and 1700 × 10, respectively). -15 m 2 ), and the porosity is estimated to be 8.5%.

[0121] Using the apparatus shown in Figure 4, 70 and 1940 g of CO2 and H2O were added, respectively. -1 The target mass of CO2 was injected. CO2 and H2O were released at a depth of 330-360 m. At this depth, CO2 was released through a sparger in the form of small bubbles into the flowing H2O. The CO2 and H2O mixture was released from the sparger into the underground rock via a mixing pipe extending to a depth of 540 m. A static mixer was installed along the way (about 420 m) to help dissolve the CO2. Over the course of three months, approximately 175 tons of CO2 and 5,000 tons of H2O were injected underground.

[0122] Complete dissolution of CO2 during injection was confirmed by digital downhole camera (showing no CO2 bubbles) and by sampling the pressurized well water using a custom-built bailer.

[0123] The image shows that there are no gas bubbles in the well water, and CO2 is completely dissolved 1.5 m from the fluid outlet at 540 m.

[0124] Twelve well water samples were analyzed for total dissolved inorganic carbon, and six of the samples had in situ pH measurements. In all cases, the dissolved inorganic carbon concentrations in the sample solutions were within 5% of the 0.82±2% mol / kg concentration based on the measured mass flow rates of CO2 and HO entering the well, and the solution pH was 3.89±0.1, confirming that CO2 was completely dissolved during injection.

[0125] Therefore, when injected underground in dissolved form, CO2 does not bubble or have buoyancy, making it highly unlikely to escape into the atmosphere (Ref.15: Gilfillan et al, 2009).

[0126] Example 10: Furthermore, experimental injection of CO2 / H2S was carried out with the following parameters: [Table 0]

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

[0128] The pH value of water with dissolved CO2 decreases as the CO2 content of the water increases with increasing CO2 pressure. 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's downward velocity in this example was about 0.7 m / s. As can be seen from the table above, the water's downward velocity in this example was about 0.7 m / s, and changing the water's downward velocity to about 0.3 m / s resulted in failure.

[0129] In the claims, the word "comprising" does not exclude other elements or steps, and the indefinite article "a" or "an" does not exclude a plurality. A single processor or other unit may fulfill the functions of several items recited in a claim. 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 entirety. [Table REF]

Claims

1. Carbon dioxide (CO ２ ) and / or hydrogen sulfide (H ２ Methods for reducing S: Pumping or transferring water from a water source into the outer pipe (205) of the injection well (210) to create a pressurized water flow within said outer pipe (205); CO in the injection pipe (206) of the injection well (210) ２ and / or H ２ S-rich gas is fed into the injection tube (206) to generate 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 pipe (205) is ２ and / or H ２ Pressure of S (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 By combining the S-rich gas stream with the CO ２ and / or H ２ the pressurized water stream of the S-rich gas stream, ２ and / or H ２ dissolving substantially all of the S gas; The water flow is increased 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 by transporting it 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 resulting pH value of said S-containing pressurized water stream 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 the pressurized water stream containing S into a geological reservoir containing reactive rock at h1+h2 or at a depth > (h1+h2).

2. 10. The method of claim 1, wherein the underground 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 10. 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 downward 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, wherein 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 10. The method according to any of the preceding claims, wherein the pressure (V) is about 20 to 36 bar, preferably about 22 to 34 bar, more preferably about 24 to 32 bar, and most preferably about 24.5 bar.

7. H at the confluence at depth h1 ２ Pressure p (H ２ 3. The method according to any of the preceding claims, characterized in that S) is about 4 to 8 bar, preferably about 5 to 7 bar, more preferably about 5.5 to 6.5 bar, most preferably about 6 bar.

8. 10. 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 pipe (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 pipe (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 concentrations of S and tracer substances, 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 tracer material; CO in the monitoring well (610) ２ and / or H ２ and comparing the molar ratio of S to the tracer material with the predetermined molar ratio in the pressurized water flow at the depth h1 of the outer pipe (205) in the injection well (210 / 612). ２ and / or H ２ Determining a reduction index that indicates the degree of reduction of S.

9. Carbon dioxide (CO ２ ) and / or hydrogen sulfide (H ２ System for reducing S: - injection well (210); an outer pipe (205) extending downwards inside said injection well (210); an injection pipe (206) extending downwardly inside 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 generating pressurized CO ２ , and / or pressurized H ２ CO containing ２ and / or H ２ means for producing an S-rich gas stream; The water pressure p(W) of the water in the outer pipe (205) is ２ and / or H ２ Pressure of S (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 the S-rich gas stream with the S-rich gas stream; - 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), wherein at h1+h2, the CO 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 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; Dissolved CO ２ and / or H ２ means for injecting said pressurized water stream containing S into a subsurface reservoir containing reactive rock at h1+h2 or at a depth > (h1+h2).

10. 10. The system according to claim 9, further comprising 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, wherein the injection pipe (206) extends downward into the outer pipe (205) and has an open end at the depth h1≧0.

12. A 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 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 the pressurized water flow at the depth h1 of the outer pipe (205) in the 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 concentrations of S and tracer substances, 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 tracer material; CO in the monitoring well (610) ２ and / or H ２ and comparing the molar ratio of S to the tracer material with the predetermined molar ratio in the pressurized water flow at the depth h1 of the outer pipe (205) of the injection well (210 / 612). ２ and / or H ２ A means for determining a reduction index indicating the degree of reduction of S.

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