How to reduce 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 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] 2. Background of the Invention Carbon dioxide (CO2) and hydrogen sulfide (H2S) are gases that are released in large quantities during various industrial processes, including the combustion of fossil fuels. These two gases pose significant challenges to the environment.

[0003] Reducing industrial CO2 emissions is one of the main challenges of this century (Ref.1: Broecker and Kunzig). Generally, CO2 emissions from geothermal sources are relatively low and they are classified as renewable energy, in contrast to conventional fossil fuel power plants, which buy and sell permits (called "emission 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 plants have been exempt from purchasing CO2 emission allowances because of their low greenhouse gas emissions, but as climate change policies become tougher, the price of CO2 emissions is expected to rise.

[0006] Hydrogen sulfide emissions from geothermal power plants are one of the environmental concerns in 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. 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 even death if the concentration of H2S in the air exceeds 300 ppm.

[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 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 case, to reduce the amount of CO2 released into the atmosphere, whether due to geothermal or other power plants, CO2 reduction in underground structures is an attractive, albeit still relatively unexplored, possibility. The standard method of underground carbon storage and sequestration is to inject CO2 as bulk into geological formations at depths of more than 800 m. At this depth, CO2 is in a supercritical state and is buoyant with respect to the fluids in the host rock. As a result, the buoyant CO2 can be transported to shallower subsurface or back to the surface (Ref.6: Hawkins; Ref.7: Benson).

[0009] Gislason et al. (Ref. 8) describe in a general way the capture of CO2, which is transported as a high-pressure gas in a 3 km pipeline to a pilot injection site. The method envisaged involves injecting CO2 together with water and letting the injected CO2 flow further down the well, which according to the authors of the publication results in a single fluid phase entering the sequestration formation. Similarly, Sigfusson et al. (Ref. 16) describe the injection of about 175 tonnes of CO2 dissolved in 5000 tonnes of water into porous rocks located 400-800 m below the surface (at a depth of about 350 m below the surface), pointing out the fact that even though large amounts of water are required to store CO2 in this way, CO2 is dissolved and therefore not buoyant, and can be stored at shorter distances from the surface than in the case of 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, and point out the fact that the great depth and high temperature allow larger amounts of CO2 and H2S to be injected than would be possible if injected into shallower, cooler rock formations.

[0010] The methods described in detail in these publications are different from the method of the present invention. Thus, none of these publications points out the importance of the relationship between the downward velocity of the water flow and the ability to efficiently ensure that the CO2 and / or H2S released at the confluence as bubbles of a given dimension are maintained in solution at a given depth / pressure. Thus, the publications are silent about the importance of transporting the water, which is confluent with a gas stream rich in CO2 and / or H2S, downward at a velocity higher than the upward velocity of the CO2 and / or H2S gas bubbles dissolved in the water. In fact, quite the opposite (Ref. 16) simply points out the importance of dissolving the carbon dioxide in the water more generally during injection, only mentioning typical volumetric flow rates and average residence times, and focusing on the importance of keeping the water to CO2 mass ratio constant. 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 points out the relevant discovery of the present invention that the demand for water can be reduced simply by increasing the downward flow rate of the 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 have reviewed processes available for the abatement of H2S, for example in geothermal power plants (Ref. 9). Most known methods involve the oxidation of H2S to elemental sulfur or sulfuric acid. The value of these products is low because there is too little demand or an oversupply. Disposal of these products is costly and can pose 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] From the above, it can be seen that there is a need for new cost-effective and environmentally friendly methods of reducing CO2 and H2S, whether from geothermal or other power plants. The inventors have discovered a new method to facilitate safe and permanent geological storage of CO2 and H2S. In this method, the demand for water 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, at 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 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 there is provided a method for storing carbon dioxide (CO2) and / or hydrogen sulfide (HS) in a geological reservoir, comprising: · Pumping (or otherwise transporting) water from the water source to the injection well; dissolving the CO2 and / or H2S gas in the water by joining a CO2 and / or H2S rich gas stream with the water under conditions where the hydraulic pressure of the water is lower than the partial pressure of the 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 said pressurized water stream containing said dissolved CO2 and H2S between about 2 and 4, preferably between about 2.5 and 3.5, 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 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, 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 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, the term partial pressure or simply pressure of a gas (of CO2 and / or H2S) 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 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, the pressure of the dissolved CO2 and / or H2S during the downward transport of water is less than the hydraulic pressure of the water (thereby keeping it in solution), so that the CO2 and / or H2S remain dissolved in the water, reducing the risk of leakage and greatly improving safety. The method according to the present invention also allows for a significant reduction in the demand for water by increasing the downward flow rate of the water. For example, the diameter of the pipe surrounding the junction of the CO2 and / or H2S-rich gas stream with the water can be simply reduced. The injection of CO2 promotes carbonization of the host rock, allowing for safe long-term storage of CO2 underground. Thus, a method is provided in which the water-rock reactions occurring in the natural reactive rocks of the geothermal system, e.g. a basalt reservoir, are exploited by means of injecting CO2 and / or H2S into the reservoir geothermal system. This allows for a reduction in the environmental impact of CO2 and H2S gas emissions, e.g. from geothermal power plants. Additionally, safe long-term storage of CO2 or 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 given rate of water descent.

[0026] In addition, 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. Returning CO2 and H2S to their original sites is considered an ideal method for reducing gas emissions from geothermal power plants, etc.

[0027] In the method and system 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 water pressure (thereby maintaining it in solution) so that the gas remains dissolved in the water and does not degas from the water. In this manner, the method of the present invention minimizes the risk of gas bubbling out of the water, which would otherwise not be 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 prior to injection into the water is greater than the water pressure, there will be gas bubbles 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 stream 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 such 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. At the same time, 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, no external energy is required at or below the confluence to obtain or maintain the necessary hydraulic pressure, since 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 moving the water and gas to the appropriate depth. Furthermore, the method according to the invention ensures that when CO2 and / or H2S are 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, they do not start to "bubble" after injection, but instead remain in solution, i.e., for the time frame required for the mineralization water-rock reaction of CO2 and / or H2S to occur. This is similar to avoiding the scenario where, when a bottle of carbonated drink is opened, carbon dioxide starts to bubble, resulting in the release of carbon dioxide from the bottle into the atmosphere. In this way, no carbon dioxide bubbling occurs if the bottle is opened under ambient pressure equal to or greater than the pressure in the bottle. The method according to the invention further ensures that the low pH of the water, due to the presence of dissolved CO2 and / or H2S therein, can promote the dissolution of minerals in the geological reservoir, thereby providing the cations required 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 located at a depth greater than the open end of the injection tube, and the water is pumped into the space between the outer tube and the injection tube. The depth of the injection tube opening in the outer tube is selected such that the water pressure in the outer tube at the opening of the injection tube is less than the pressure of the CO2 and / or H2S gas in the injection tube, while at the same time the water is transported downwards at a rate 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 such that the drag of the downward flowing water on the injection well is greater than the buoyancy of the CO2 and / or H2S. Thus, a constant downward water flow is provided, ensuring that the dissolved CO2 and / or H2S moves downward, 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, 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 temperature of the water 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 at said open end of the outer tube is selected such that the pH value2 of the injected water containing dissolved CO 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 rocks begins, i.e. the storage of carbon dioxide CO2 and hydrogen sulfide H2S in the formation begins. The lower the pH value, the faster the rate of dissolution of the rocks, and the lower pH value will significantly promote the sequestration of carbon dioxide CO2 and hydrogen sulfide H2S 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, for example using a sparger and / or mixer, to obtain a homogenous mixture of CO2 and / or H2S gas in the water, which breaks up large bubbles and dissolves the 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 enhancing the dissolution of CO2 and / or H2S gas below the confluence. Also, the large CO2 and / or H2S bubbles are broken up into smaller bubbles, enhancing the dissolution of CO2 and / or H2S.

[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 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 distributes the CO2 and / or H2S gas bubbles evenly 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 in 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 enhancing the dissolution of CO2 and / or H2S gas. It also causes large CO2 and / or H2S gas bubbles to break up into smaller bubbles, which increases the rate of dissolution 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 such 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, the water is transported 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 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, firstly to allow the CO2 and / or H2S gas to enter the water of the injection well at the confluence depth, and secondly to ensure that the water pressure at the slightly greater depth, after dissolving in the water and moving downward at a given downward velocity, is greater than the pressure of the CO2 and / or H2S. Therefore, by choosing 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 that the CO2 and / or H2S 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, facilitating 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 the CO2 and / or H2S, the estimating step comprising: dissolving a tracer substance in the water in addition to said CO2 and / or H2S, in such a manner that the concentrations of the dissolved CO2 and / or H2S and the dissolved tracer substance are controlled such that the initial molar ratio of the CO2 and / or H2S to the tracer substance is predetermined; monitoring a 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 a well interconnected with the injection well via a flow path such that at least a portion of the injection water mixed with dissolved CO2 and / or H2S and the tracer substance flows to the monitoring well via the flow path, the monitoring including measuring concentrations of the CO2 and / or H2S and the tracer substance at the monitoring well and determining a 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 material may be, but is not limited to, SF5CF3 tracer, SF6 or rhodamine tracer (all conservative tracers), or C-14 tracer that only tracks carbon. One or more of these tracers may be used simultaneously.

[0043] Similarly, by dissolving KI in pressurized water and using a tracer substance such as iodide ion, it is possible to 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 performing a correction of the aversion index to account for oxidation of H2S by other sulfide species, which results in a more accurate estimation of the abatement potential. The correction is performed by analyzing other types of sulfur in the geothermal water from the injection well and comparing it with the value obtained before injecting H2S, and correcting the excess sulfur species formed by oxidation of H2S (e.g., SO4) before calculating the abatement index for H2S. 2- or S2O3 - ) to the value of H2S.

[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 further includes providing a constriction at the open end of the injection tube to maintain high water pressure within the injection tube to further ensure that the CO2 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 conveying water from the water source to the injection well; · Means of 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 the CO2 and / or H2S; means for transporting the water flow from the depth h1≧0 to a greater depth h1+h2 (h1+h2>h1) at a downward flow velocity that is greater than the upward flow velocity of the CO2 and / or H2S gas bubbles due to buoyancy forces on the CO2 and / or H2S gas bubbles in the water; means for maintaining a resultant pH value of said pressurized water stream containing dissolved CO2 and H2S at about 2 to 4, preferably at about 2.5 to 3.5, more preferably at about 3.2; and · Means for injecting said water containing 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 tube for conducting high pressure CO2 and / or H2S gas to an injection well, the injection tube having an open end extending into the injection well at a depth h1≧0 selected such 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, 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 a depth equal to or greater than h1, thereby enabling the water to be transported to a depth 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 tube surrounding said injection tube having an open end extending downwardly into said injection well at a depth h1+h2, said pumping means being a water pump pumping water into a space between the outer tube and the injection tube, and said means for injecting dissolved CO2 and / or H2S into the geological reservoir is a downward flow rate of water and a resulting flow rate formed by pumping water into said space between the outer tube and the injection tube. In gas limited CO2 situations, h1+h2 may be selected such that the pH value of the injection water containing dissolved CO2 is below a pre-set pH limit.

[0050] In one embodiment, the means for dissolving CO2 and / or H2S in water further comprises: a sparger attached to said 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 homogenous 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 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 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, capable of dissolving any remaining CO2 and / or H2S bubbles in the water.

[0051] Thus, a practical and cost-effective system is provided for in situ mineral carbonation in reactive rocks, e.g., basalt, in which water is injected with a high enough concentration of dissolved CO2 and / or H2S to promote reaction with the reactive rock, e.g., basalt. 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 according to the present invention, once dissolved, the CO2 and / or H2S loses its buoyancy, reducing the risk of leakage and dramatically improving safety. In addition, the injection of 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, sea water, etc. The water source may therefore be any type of water. Similarly, the CO2 and / or H2S 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. In relation to the present invention, the following is further disclosed: [1] Carbon dioxide (CO 2 ) and / or hydrogen sulfide (H 2 How to reduce S: Pumping or transferring 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 Pressure of S (p(CO 2 ) and / or p(H 2 At a depth h1≧0 lower than S), the pressurized water flow and the CO 2 and / or H 2 The CO 2 and / or H 2 The pressurized water stream of the S-rich gas stream is 2 and / or H 2 dissolving substantially all of the S 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 2 and / or H 2 The upward flow velocity 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; 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, 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] The method according to [1], characterized in that 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 reduce the amount of CO dissolved in the water stream. 2 and / or H 2 Any of the preceding methods, further comprising increasing the interfacial area between S. [4] 2. 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] The method according to [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 ) 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 S) is about 4 to 8 bar, preferably about 5 to 7 bar, more preferably about 5.5 to 6.5 bar, and most preferably about 6 bar. [8] Any of the preceding methods further comprising the steps of: The dissolved CO 2 and / or H 2 dissolving a tracer substance in a predetermined molar ratio compared to S; a monitoring well (610) interconnected to the outer tube (205) of the injection well (210 / 612) via a flow passage (614), thereby detecting 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 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 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 To determine a reduction index that indicates the degree of reduction of S. [9] Carbon dioxide (CO), including 2 ) and / or hydrogen sulfide (H 2 A system for reducing S: · 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 pumped 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 Pressure of S (p(CO 2 ) and / or p(H 2 At a depth h1≧0 lower than S), the pressurized water flow and the CO 2 and / or H 2 means for combining the 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 due to 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) means of becoming higher; 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] The system according to [9], further comprising a means for sparging (207) attached to the injection pipe (206) at a junction at a depth h1≧0.

[11] The system of any of [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] The system described in any one of [9] to

[11] , characterized in that the outer pipe (205) has an open end at the depth h1 + h2.

[13] The system according to any one of [9] to

[12] , further comprising: 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 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 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 that indicates the degree of reduction in S. [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 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 a fracture in hot rock that expands in a direction other than upward and downward and provides a flow path for injection 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 a second step (S2) 103, the CO2 and / or H2S gas is merged into the water at a junction where the water pressure is lower than the CO2 and / or H2S pressure, but at the same time, the water is transported downwards 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 pressures of 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 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 flow into the water at a depth h1≧0, while at the same time ensuring that the water is transported to a depth 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, promoting CO2 water-rock reactions in the geological reservoir.

[0062] One of the key aspects of the present invention is the dissolution of CO2 (and / or H2S) in water prior to dispersion as a single-phase fluid into the pore space of reactive rock. CO2 dissolves to form carbonic acid (H2CO3), which is converted to 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 S 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 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] After the injection of CO2 or H2S, 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 a schematic of the interaction of host rocks with formation fluids during in situ CO2 ore sequestration following CO2 injection into injection well 2000. 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. Further away from the injection well, clays and zeolites compete with carbonates for dissolved cations, resulting in 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 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 said water source is increased to form pressurized water. This 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 gas being dissolved.

[0070] In step (S3″) 203, CO2 and / or H2S gas is dissolved in pressurized water, the water pressure being selected such that the water pressure is lower than the CO2 and / or H2S gas pressure during dissolution of the gas. The water pressure is, in one embodiment, about 6 bar or somewhat lower than the CO2 and / or H2S gas pressure. In this embodiment, said step (S3) 105 of injecting the dissolved H2S 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 selected such that the water pressure in the injection well, where the open end of the injection tube is located, is small, but is greater than the pressure of the dissolved CO2 and / or H2S at a somewhat greater depth h2 reached as the water flows downwards. This is so that when the water with dissolved CO2 and / or H2S emerges from the open end of the injection tube, the surrounding pressure is greater than the dissolution pressure of CO2 and / or H2S. Doing so allows the CO2 and H2S to remain dissolved long enough to initiate mineralization water-rock reactions of CO2 and H2S. At the same time, the low pH of the water containing 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 the water, and by mixing the dissolved H2S into the water to mix the H2S uniformly in the water, and by dissolving any remaining H2S gas bubbles in the water.

[0071] In one embodiment, said step (S3) 105 of dissolving CO2 and / or H2S gas in water consists of conducting CO2 and / or H2S gas through an injection tube having an open end extending downwards into said 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. Preferably, the water pressure is slightly less than the pressure of the CO2 and / or H2S gas in the tube at this open end. This is firstly to ensure that the CO2 and / or H2S gas enters the water of the injection well and secondly to ensure that the water pressure at its greater depth h1+h2 (i.e. the water pressure after the CO2 and / or H2S gas has been injected) after it has entered the water at a depth h1≧0 and traveled some distance downward with the water flow is greater than the pressure of the CO2 and / or H2S dissolved in the water. The injection pipe may be, 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] FIG. 4 illustrates an 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 delivered to an injection well 210 via a gas injection pipe 206 with an open end at a depth h1≧0, surrounded by an external water injection pipe 204 with 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, 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 tube at depth h1 ≥ 0 is selected so that the water pressure at this depth is slightly less than the pressure of the CO2 gas in the injection tube. This is to allow the CO2 gas to enter the water.

[0074] The flow rate of the water into the space between the injection tube 206 and the outer tube 204 is selected so that the water flow rate, indicated by the arrows, is greater than the rate at which the 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, making the bubbles smaller and slowing their rate of rise. Smaller bubbles are favorable conditions because they rise less quickly and have a larger surface area, which increases the rate of dissolution.

[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] 4, a sparger 207 is placed at the open end of the injection tube 206 to maximize the interfacial area between the CO2 gas and the water. This allows the CO2 gas bubbles to be evenly distributed in the water, further reducing the average bubble diameter, thereby 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 remaining CO2 gas bubbles in the water. This creates more turbulence, which further promotes the dissolution of the CO2 gas. It also splits the large CO2 gas bubbles into smaller ones, which increases the dissolution rate of the CO2.

[0078] In one embodiment, the depth h1 of the water column in the outer tube is about 250 m, which means that the water pressure is 24.5 bar. This means that the pressure of the CO2 gas is slightly more than 24.5 bar. As the CO2 gas leaves the opening of the injection tube 206 and passes through the sparger 207, it immediately disperses into small bubbles and then dissolves in the water. Due to the constant water flow in the space between the injection tube and the outer tube 204, a vertical downward velocity is created, which moves the dissolved CO2 towards the open end of the injection tube at said depth h1+h2. This depth is preferably selected so that the pH value of the dissolved CO2 is about 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 leaves the system 200 and the trapping 2 of CO2 in the basalt rock 2 begins. Also, the lower the pH value, the higher the dissolution rate in the basalt rock.

[0079] An additional advantage of the present invention is its low cost compared to conventional technologies. The overall "on-site cost" of capturing, transporting and storing this mixed gas at the CarbFix2 Hellisheioi site is US$24.8 / ton of mixed gas CO2 / H2S, which is significantly lower than the prices reported by others (US$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 a deep geological site.

[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] With reference 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 an outer pipe (205) of an 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 tube (206) of an injection well (210) to generate a CO2 and / or H2S rich gas stream comprising pressurized CO2 and / or pressurized H2 in said injection tube (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 with 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 said water stream in solution by transporting said water stream from said 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 said CO2 and / or H2S gas due to buoyancy forces on CO2 and / or H2S gas bubbles in said water stream at said depth h1+h2; Injecting said pressurized water stream containing dissolved CO2 and / or H2S into a reactive rock reservoir at h1+h2 or at 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 250-750 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 pressure of CO2 at the junction at 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.

[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 3-9 bar, such as 4-8 bar, preferably about 5-7 bar, more preferably about 5.5-6.5 bar, such as 5.6-6.4, for example 5.7-6.3 bar, most preferably about 6 bar.

[0090] In a further particularly preferred embodiment of the method according to the invention, the resultant pH value of said pressurized water stream containing said dissolved CO2 and / or H2S 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 compared to the dissolved CO2 and / or H2S in the pressurized water flow at the depth h1≧0 of the outer tube (205) in the injection well (210 / 612); - 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 said monitoring well (610) and, based thereon, establishing a molar ratio of CO2 and / or H2S and the tracer substance in said monitoring well (610); and determining a reduction index indicative of the degree of reduction of CO2 and / or H2S based on comparing the molar ratio of CO2 and / or H2S to the tracer material in the monitoring well (610) with the predetermined molar ratio in the pressurized water flow at the depth h1 of the outer tube (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 (H2S), 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); means for feeding a CO2 and / or H2S rich gas into said injection tube (206), thereby generating a CO2 and / or H2S rich gas stream comprising pressurized CO2 and / or pressurized H2 in said injection tube (206); means for merging the pressurized water stream with 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 stream from said 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 buoyancy forces on the CO2 and / or H2S gas bubbles in the water stream at said depth h1+h2; means for maintaining a resultant 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 at 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: 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 the depth h1≧0 in the outer tube (205) of the injection well (210 / 612); ·Monitoring wells (610); a flow path (614) through which at least a portion of the pressurized water containing 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 and the tracer substance in said monitoring well (610); means for determining a reduction index indicative of 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 tube (205) of the injection well (210 / 612).

[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 CO2 comes from a gas purification unit or gas separation station of a geothermal power plant. The initial pressure of the gas is 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. Including other pressure losses, 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 partial pressure of carbon dioxide is chosen to be 25 bar downhole. This means saturation at 25 bar pressure, which means 36 g CO2pr.kg of water at 17°C. 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 of the gas forms small bubbles that travel down the pipe with the water. At greater depths, the pressure is higher and the bubbles become smaller, dissolving more of the gas 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 flow channel 614, which may be, for example, a fracture in the underground reservoir. The implementation of this monitoring well 610 is to estimate the mineralization potential of CO2. The estimating step includes using one or more tracer substances to trace CO2 gas, or water, or carbon. In this way, one or more types of tracer may be added via a suitable tracer source to trace one or more of these, such that the molar ratio between CO2 gas, or water, or carbon and the tracer substance(s) is predetermined, i.e., the molar ratio is pre-fixed. This means that only one tracer can be used to trace, for example, only CO2, only C, only water, or a combination thereof. As an example, SF5CF3 tracer, SF6 tracer or rhodamine tracer can be implemented to trace 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 the CO2 changes as a result of the CO2-water-rock interaction, and therefore the mineralization of the injected CO can be estimated when performing mass balance calculations. A monitoring device (not shown here) may be provided to monitor the molar ratio between CO2 gas, or water, or carbon, and the tracer material(s) in the monitoring well 610 as a result of the injection of the dissolved CO2. As already mentioned, the monitoring well 610 is connected to the injection well 612 through the flow path, and at least a part of the injection water mixed with the dissolved CO2 and 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, a reduction index indicating the amount of CO2 stored by water-rock reactions can be obtained. Thus, 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 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. Figure 5 shows an embodiment of a method according to the invention for removing hydrogen sulfide in a geothermal reservoir, where the H2S mineralization potential is estimated, which can be carried out 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 the 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, which is in communication with the injection well through a flow path such as a crack or fissure in rock, and through which at least a portion of the injection water mixed with the dissolved H2S as the tracer material flows into the monitoring well. This monitoring includes measuring the concentrations of H2S and the tracer material in the monitoring well and measuring the molar ratio of H2S to the tracer material based on the concentrations.

[0109] In step (S6) 305, the molar ratio of H2S to the 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 reaction. For example, if the molar ratio of H2S to the 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 by water-rock reaction. However, to further improve this method, it would be desirable to make a correction to account for the oxidation of H2S to other sulfur species, which is a source of uncertainty.

[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. The total depth of such a well may be 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 within rock 402. Water-rock reactions occurring in geothermal reservoirs are illustrated in the close-up of 404, which shows the flow path of dissolved H2S in the rock, which 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 fresh water source (cold water) is used instead of a geothermal water source.

[0112] Example 6: FIG. 9 shows diagrammatically an embodiment of a system 500 according to the invention for reducing hydrogen sulfide (H2S) in a geothermal reservoir 501. The system includes a H2S 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. H2S is delivered at high pressure to the wellhead 509 and delivered 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 (in 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 tube 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 tube. 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 such that the volumetric flow rate and therefore velocity of the water (indicated by the arrows) is greater than the upward velocity of the H2S gas due to buoyancy forces on the H2S gas at the open end of the injection pipe. Thus, as the H2S gas bubbles move downwards, the water pressure increases, causing them to become smaller, which in turn reduces their upward velocity. Smaller bubbles are favorable conditions as they reduce the upward velocity of the bubbles and also provide a larger total surface area, enhancing the rate of dissolution.

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

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

[0117] Example 7: 10 illustrates another embodiment of a system 600 according to the present invention for removing (reducing) hydrogen sulfide (H2S) in a geothermal reservoir. 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. The implementation of this monitoring well 610 is for estimating H2S mineralization potential, as described above in connection with FIG. 5.

[0118] Example 8: FIG. 11 shows diagrammatically yet another embodiment of a system 700 according to the invention for mitigating (reducing) hydrogen sulfide (H2S) in a geothermal reservoir. 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 low, therefore a higher water flow rate can be maintained, 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 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, CO2 and H2O were pumped at 70 and 1940 gs, respectively. -1 The target mass of CO2 was injected at 1000m. The CO2 and H2O were released at a depth of 330-360m. At this depth, the 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 rocks via a mixing tube that extended to a depth of 540m. Along the way (about 420m), a static mixer was installed to help dissolve the CO2. Over the course of three months, about 175 tonnes of CO2 and about 5000 tonnes of H2O were injected underground.

[0122] Complete dissolution of the CO2 during injection was confirmed by a digital downhole camera (showing the absence of CO2 bubbles) and by sampling of the pressurized well water using a custom-built baler.

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

[0124] Twelve well water samples were analyzed to measure total dissolved inorganic carbon, and six of the samples had in situ pH. In all cases, the dissolved inorganic carbon concentrations of the sample solutions were, on average, within 5% of the concentration of 0.82 ± 2% mol / kg based on measured mass flows of CO2 and H2O entering the well, and the solution pH was 3.89 ± 0.1, confirming that the CO2 was completely dissolved during injection.

[0125] Therefore, when injected underground in dissolved form, CO2 has no bubbling or buoyancy and is therefore very unlikely to escape into the atmosphere (Ref.15: Gilfillan et al, 2009).

[0126] Example 10: In addition, experimental injection of CO2 / H2S was performed 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 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. Carbon dioxide (CO) is produced by mineralization and precipitation in a geological reservoir containing reactive rocks, the process including the steps of: ２ ) carbon and / or hydrogen sulfide (H ２ Methods for reducing sulfur (S): - pumping or transporting water from a water source into an outer pipe (205) of an injection well (210) to create a pressurized water flow in said outer pipe (205), said outer pipe (205) having an open end at a depth h1+h2; CO 2 is injected into an injection tube (206) that extends inside the outer tube (205) downward into the injection well (210). ２ and / or H ２ S-rich gas is pumped into the injection tube (206) to pump 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 The pressurized water flow and the CO2 flow are separated from each other by providing an open end to the injection pipe (206) at a depth h1≧0 lower than the depth h1≧0 of the outer pipe (205). ２ and / or H ２ by merging the S-rich gas stream; and The combined pressurized water flow and the CO ２ and / or H ２ a S-rich gas stream from the depth h1≧0 to the open end of the outer tube (205) at the depth h1+h2 ((h1+h2)>h1), 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 S), by transporting the water at a higher downward flow velocity v(W) at depth h1+h2. The CO ２ and / or H ２ The pressurized CO of the S-rich gas stream ２ and / or H ２ dissolving substantially all of the S gas; CO dissolved in the outer tube (205) ２ and H ２ The resulting pH value of the pressurized water stream containing S is maintained at 2-4, thereby reducing the amount of dissolved CO ２ and H ２ When the pressurized water stream containing S is contacted with minerals in a geological reservoir containing reactive rocks, Ca is extracted from the reactive rocks. ２＋ , Mg ２＋ , Fe ２＋ promoting the dissolution of cations and dissolution of minerals selected from the group consisting of: CO dissolved in the outer tube (205) ２ and / or H ２ injecting the pressurized water stream containing S into the underground reservoir containing reactive rock at h1+h2 or at a depth > (h1+h2); Thereby, promoting the dissolution of minerals from reactive rocks in the geological reservoir and reducing the amount of dissolved carbon dioxide (CO ２ ) and / or hydrogen sulfide (H ２ S) to provide the cations necessary for carbon and sulfur reduction and carbon and sulfur mineralization.

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

3. At the junction at 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 The method of any one of claims 1 to 2, further comprising increasing the interfacial area between S.

4. CO at the confluence at depth h1 ２ Pressure p(CO ２ 4. The method according to claim 1, wherein the pressure in the atmosphere is from 20 to 36 bar.

5. H at the confluence at depth h1 ２ Pressure p of S (H ２ 5. The process according to claim 1, wherein the pressure in the range of from 4 to 8 bar is S).

6. The method according to any one of claims 1 to 5, further comprising the steps of: 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 detecting dissolved CO ２ and / or H ２ at least a portion of the pressurized water stream 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; 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 determining a reduction index indicative of the degree of reduction of S; Thereby, the dissolved CO ２ and / or H ２ To determine the extent to which the geological reservoir has the capacity to store carbon and sulfur in the mineralogy of S.

7. Carbon dioxide (CO) injected into a geological reservoir containing reactive rocks through mineralization and precipitation ２ ) carbon and / or hydrogen sulfide (H ２ A system for reducing sulfur in a geological reservoir, the mineralization and precipitation promoting dissolution of minerals from reactive rocks in the geological reservoir and reducing dissolved carbon dioxide (CO) in the geological reservoir. ２ ) and / or hydrogen sulfide (H ２ S) and providing the cations necessary for carbon and sulfur reduction and carbon and sulfur mineralization; - injection well (210); an outer tube (205) having an open end at a depth h1+h2 and extending downwards inside said injection well (210); an injection pipe (206) having an open end at a depth h1≧0 and extending downwards inside the injection well (210) inside the outer pipe (205); - means for pumping or redirecting 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 pumping pressurized CO ２ , and / or pressurized H ２ CO containing S 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 depth h2 of the outer pipe (205) in the form of an open end of the injection pipe (206), ２ and / or H ２ means for combining said S-rich gas stream with said S-rich gas stream; The combined pressurized water flow and the CO ２ and / or H ２ a S-rich gas stream from the depth h1≧0 to the open end of the outer tube (205) at the depth h1+h2 ((h1+h2)>h1), 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 a means for conveying the water at a higher downward flow velocity v(W) at a depth h1+h2 than the water at a depth h1+h2; CO in the outer tube (205) ２ and H ２ The resulting pH value of the pressurized water stream containing S is maintained at 2-4, thereby reducing the amount of dissolved CO ２ and H ２ When the pressurized water stream containing S is contacted with minerals in a geological reservoir containing reactive rocks, Ca is extracted from the reactive rocks. ２＋ , Mg ２＋ , Fe ２＋ a means for promoting the release of cations and dissolution of minerals selected from the group consisting of: CO in the outer tube (205) ２ and / or H ２ means for injecting said pressurized water stream containing S into said underground reservoir containing reactive rock at h1+h2 or at a depth > (h1+h2); The system comprising:

8. 8. The system of claim 7, further comprising sparging means (207) attached to the injection pipe (206) at a junction at a depth h1≧0.

9. The system of any one of claims 7 to 8, further comprising: 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 tube (205) in said injection well (210 / 612); -Monitoring well (610); Dissolved CO ２ and / or H ２ a flow path for at least a portion of the pressurized water stream mixed with S and the tracer material to flow 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 means for determining a reduction index indicative of the degree of reduction of S; and Thereby, CO ２ and / or H ２ A means for determining the extent to which said geological reservoir has the capacity to store carbon and sulfur of S in mineralogy form.

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