System for emission reduction of carbon dioxide and / or hydrogen sulfide in geological reservoirs

Abstract

The present invention relates to a system for emission reduction of carbon dioxide and / or hydrogen sulfide in a geological reservoir. Water is pumped or transferred from a water source to an injection well. The gas is combined with the water under conditions where the hydraulic pressure of the water is lower than the CO2 and / or H2S gas pressure at the combination point. The water with the CO2 and / or H2S bubbles is further transferred downward at a speed higher than the upward flow rate of the CO2 and / or H2S bubbles, ensuring that the bubbles move downward, resulting in complete dissolution of the CO2 and / or H2S in the water due to an increase in pressure. Complete dissolution ensures a lower pH of water entering a geological (e.g. Geothermal) reservoir, which is required to promote mineral reactions that result in CO2 and H2S emissions. This emissions may be quantified by dissolving tracer substances in a predetermined molar ratio to the dissolved CO2 and / or H2S and monitoring in a monitoring well.

Description

[0001] This application is a divisional application of the invention patent application with application number 202080037447.X, whose application date is May 22, 2020 and whose invention name is “Method for Reducing Carbon Dioxide and Hydrogen Sulfide Emissions”. Technical Field

[0002] The present invention relates to a method and system for reducing carbon dioxide (CO2) and / or hydrogen sulfide (H2S) emissions by injecting carbon dioxide (CO2) and / or hydrogen sulfide (H2S) into a geological reservoir and subsequently storing them in the geological reservoir. Background Art

[0003] Carbon dioxide (CO2) and hydrogen sulfide (H2S) are two gases that are often released in large quantities during a wide range of industrial processes, such as the combustion of fossil fuels. Both gases pose important challenges to the environment.

[0004] Reducing industrial CO2 emissions is one of the major challenges of this century (Reference 1: Broecker and Kunzig). In general, CO2 emissions from geothermal resources are relatively low, and these resources are classified as renewable energy. This is in contrast to conventional power plants that run on fossil fuels, which buy and sell pollution permits (called "allowances").

[0005] Conventional geothermal power plants utilize the heat of the earth by utilizing a hot mixture of steam and brine from geothermal reservoirs, which are characterized by thermal anomalies, permeable rocks, and fluids (Reference 2: Barbier). Geothermal steam from these geothermal reservoirs naturally contains dissolved gases, which include both greenhouse gases CO2 and hydrogen sulfide (H2S). These gases are byproducts of geothermal energy production and are of magmatic origin. When conventional geothermal power plants are in operation, the gases in the steam are exhausted to the atmosphere.

[0006] Until now, geothermal power plants have been exempted from purchasing CO2 quotas because their greenhouse gas emissions are fairly low. However, this may change as climate change policies become more stringent, and the price of emitting CO2 is expected to rise.

[0007] Hydrogen sulfide emissions from geothermal power plants are another major environmental concern for geothermal utilization. Hydrogen sulfide is a colorless, flammable and toxic gas with a characteristic odor of rotten eggs. Exposure to it causes health problems that vary depending on the level and duration of exposure. Low-level, prolonged exposure causes eye inflammation and irritation, while short-term high-level exposure causes dizziness, headaches, nausea and even death if the concentration of H2S in the atmosphere exceeds 300 ppm.

[0008] The concentration of hydrogen sulfide in geothermal fluids is usually in the range of a few ppb to several hundred ppm (Ref. 3+4: Arnórsson). During the utilization of high temperature geothermal fluids, hydrogen sulfide is concentrated in the vapor phase and subsequently released to the atmosphere after condensation of the vapor. Every year, for example, the Hellisheiei power plant in Iceland emits 9,500 tons of hydrogen sulfide into the atmosphere without any abatement system. Hydrogen sulfide is released at the top of the cooling tower to reduce the risk of high concentrations of hydrogen sulfide near the power station. Hydrogen sulfide is blown away from the power plant site by the wind and produces a foul odor in nearby communities under some weather conditions.

[0009] To date, CO2 has been stored, for example as a supercritical fluid associated with major gas and oil production facilities, such as Sleipner in the North Sea, InSalah in Algeria, and Weyburn in Canada (Reference 5: Kerr). However, CO2 reduction in geological formations, whether from geothermal energy production or from other sources (such as, for example, conventional power plants), remains an attractive but still relatively unexplored possibility for reducing the amount of CO2 emitted to the atmosphere. The standard method for geological carbon storage / sequestration is to inject CO2 as a bulk phase into geological formations at depths >800m. At this depth, CO2 is supercritical and buoyant relative to the host rock fluids. As a result, the buoyant CO2 may migrate back to the shallow subsurface and surface (Reference 6: Hawkins; Reference 7: Benson).

[0010] Gislason et al. (reference 8) describes in a general manner a method for capturing CO2, which is transferred as a high-pressure gas in a 3 km long pipeline to a pilot injection site. In the envisaged method, CO2 will be injected together with co-injected water, which will divert the injected CO2 further down the well, which, according to the authors of the publication, results in a single fluid phase entering the sequestered formation. Similarly, Sigfusson et al. (reference 16) describes the injection of about 175 tons of CO2 dissolved in 5000 tons of water (at a depth of about 350 meters below the surface) into porous rocks located 400-800 meters below the surface, and points out the fact that even though a large amount of water is required to store CO2 by this method, it can be stored at a shorter distance from the surface than in the case of supercritical CO2, because the CO2 is dissolved and therefore no longer buoyant. Similarly, Gunnarson et al. (Reference 17) described the continuous injection of CO2 and H2S (dissolved in water at a depth of about 750m below the surface) into basalt located about 2000m below the surface at temperatures ranging from 200 to 260C, and pointed out the fact that the greater depth and high temperature allowed the injection of larger quantities of CO2 and H2S than would be obtained by injection into shallower, cooler rock formations.

[0011] The methods described in detail in these publications are different from the methods of the present invention. Therefore, none of these publications point out the importance of the relationship between the downward velocity of the water flow and the ability to effectively ensure that the CO2 and / or H2S released as bubbles of a given size at the merging point remain in the solution at a given depth / pressure. Therefore, these publications do not mention the importance of transferring the water merged with the gas stream rich in CO2 and / or H2S downward at a speed higher than the upward velocity of the bubbles of CO2 and / or H2S gas dissolved in the water. In fact, on the contrary (reference 16) only points out the importance of dissolving carbon dioxide into water during injection more generally, and only mentions typical volume flow rates and average residence times, just as it focuses on the importance of fixed water and CO2 mass ratio. This means that the authors of these publications at the time obviously did not fully understand which factors can actually affect the usefulness of these methods. Similarly, none of these publications point out the relevant findings of the present invention, that is, it is therefore possible to simply increase the downward flow velocity of water, such as by reducing the diameter of the pipeline around the merging point of gas and water to reduce the water demand. This feature is of great economic importance for the feasibility of the process according to the invention compared to those described in the prior art.

[0012] A review of methods for reducing H2S emissions that can be used, for example, in the context of geothermal energy production (i.e., geothermal power plants) is provided by Sanopoulos and Karabelas (reference 9). Most known methods involve oxidation of H2S to elemental sulfur or sulfuric acid. These products have low value because demand is too low or supply is excessive. Disposal of these products is costly and creates environmental problems.

[0013] Hibara et al. (reference 10) speculated that H2S could be compressed and mixed with brine and reinjected into auxiliary wells. However, until now, no such hydrogen sulfide abatement method has been described in detail, nor is it fully understood what factors may actually affect the usefulness of such an approach.

[0014] From the above, it can be appreciated that there is a need for new, cost-effective and environmentally friendly emission reduction methods for reducing CO2 and / or H2S from geothermal energy production or other sources (e.g., conventional power plants). The inventors of the present invention have discovered a new method to promote safe and permanent geological storage / sequestration of both CO2 and H2S, which enables a significant reduction in water demand by increasing the downward flow rate of water, for example, by simply reducing the diameter of the pipe around the point where the CO2 and / or H2S-rich gas stream merges with the water. Thus, safe long-term storage of CO2 and / or H2S can be promoted simply by controlling how much CO2 and / or H2S gas is dissolved in the injected water at a given merging point and at a given water downward velocity. Summary of the invention

[0015] As discussed above, it would be advantageous to achieve an effective and environmentally friendly method for reducing carbon dioxide emissions and / or hydrogen sulfide emissions from both conventional and geothermal power plants.In general, the invention preferably seeks to mitigate, alleviate or eliminate one or more of the above mentioned disadvantages singly or in any combination.

[0016] In order to better solve one or more of these problems, in a first aspect of the present invention, there is provided a method for storing carbon dioxide (CO2) and / or hydrogen sulfide (H2S) in a geological reservoir, comprising:

[0017] Pumping (or otherwise transferring) water from a source to an injection well,

[0018] dissolving CO2 and / or H2S gas in water by combining a CO2 and / or H2S rich gas stream and water under conditions wherein the hydraulic pressure of the water is lower than the partial pressure of CO2 and / or H2S in the CO2 and / or H2S rich gas stream,

[0019] ensuring that the dissolved CO2 and / or H2S remain dissolved in the water by transferring the water comprising the dissolved CO2 and / or H2S downwards at a velocity greater than the upward velocity of the bubbles of CO2 and / or H2S gas in the water,

[0020] maintaining the resulting pH of said pressurized water stream comprising said dissolved CO2 and / or H2S between about 2 and 4, preferably between about 2.5 and 3.5, more preferably about 3.2, and

[0021] • Injection of water including dissolved CO2 and / or H2S into a geological reservoir.

[0022] In the context of the present invention, the term pumping is to be understood as any way of transferring a liquid, such as water, from one location to another.

[0023] 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, ocean / seawater, spring water, geothermal condensate or brine, or surface water from rivers, streams or lakes.

[0024] In the context of the present invention, the term injection well should be understood as any kind of structure that provides the possibility of placing fluids or gases deep underground or just into the underground in a downward direction, such as, for example, devices for placing fluids in or below reactive rock formations (such as basalt or basalt stone) and porous rock formations (for example sandstone or limestone) or shallow soil layers.

[0025] In the context of the present invention, a gas stream enriched in CO 2 and / or H 2 S is understood to be any gas stream whose relative content of CO 2 and / or H 2 S is higher than the relative content of CO 2 and / or H 2 S in the atmosphere.

[0026] In the context of the present invention, the term hydraulic pressure is understood as the pressure of the hydraulic fluid, which is exerted in all directions in a container, well, hose or anywhere else it is present. Hydraulic pressure can cause flow in a hydraulic system when the fluid flows from high pressure to low pressure. Pressure is measured in SI units of Pascal (Pa), which is one Newton per square meter (1N / m 2 ) or 1kg / (m·s 2 ) or 1J / m 3 Other commonly used units of pressure are pounds per square inch, or more precisely, pounds-force per square inch (abbreviated: psi) and bar. In SI units, 1 psi is approximately equal to 6895 Pa and 1 bar is equal to 100,000 Pa.

[0027] In the context of the present invention, the term partial pressure or simply pressure of a gas (CO2 and / or H2S) is to be understood as the nominal pressure of said given gas in a gas mixture if this given gas 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 component gases in the mixture.

[0028] In the context of the present invention, the term velocity is understood to refer to a vector quantity that refers to the rate at which an object changes its position in a certain direction. Thus, velocity is equal to distance / time, and the SI unit is m / s. Water moving in a given direction at a given speed will do so at a certain flow rate, which can be given as volume flow rate or mass flow rate. Volume flow rate is the volume of fluid passing a given point per unit time, and is usually denoted by the symbol Q (sometimes V). The SI unit for volume flow rate is m 3 / s. Therefore, volume flow rate is equal to volume / time. On the other hand, mass flow rate is the mass of fluid passing through a given point per unit time (kg / s).

[0029] In the context of the present invention, injecting or injecting is understood as forcing something into something else, ie forcing a fluid into an underground structure.

[0030] In the context of the present invention, the term geological reservoir is to be understood as a fracture in an underground structure (e.g. basalt) that expands in directions other than upwards and downwards, which structure provides a flow path for water injected into an injection well according to the present invention and may include so-called geothermal reservoirs. In the present context, the term geothermal reservoir is to be understood as a fracture in hot rock that expands in directions other than upwards and downwards and provides a flow path for injected water from a well.

[0031] The method and system of the present invention ensure that the pressure of dissolved CO2 and / or H2S is less than the hydraulic pressure of water (and therefore remains in solution) when the water is transferred downwards, which ensures that CO2 and / or H2S remain dissolved in water, which significantly improves safety due to the reduced risk of leakage. In addition, this makes it possible to significantly reduce the water demand of the method according to the present invention by increasing the downward flow rate of water (for example, by simply reducing the pipe diameter around the merging point of the gas stream rich in CO2 and / or H2S and water). The injection of CO2 promotes the carbonization of the ore-bearing rock, and therefore promotes the safe long-term storage of CO2 underground. Therefore, a method is provided, in which water-rock reactions have occurred in natural reactive rocks (for example, basalt), by injecting CO2 and / or H2S back into the reservoir geothermal system to utilize the reservoir in the geothermal system. Therefore, the impact of CO2 and / or H2S gas emissions from, for example, geothermal power plants on the environment will therefore be reduced. Likewise, safe long-term storage of CO2 and / or H2S can be facilitated simply by controlling how much CO2 and / or H2S gas is dissolved in the injected water at a given incorporation point and at a given water downward velocity.

[0032] Furthermore, the emission reduction 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 / or H2S to their source must be seen as an ideal method for reducing gas emissions from, for example, geothermal power plants.

[0033] The method and system of the present invention ensures that the fact that the gas pressure (i.e. partial pressure) of the dissolved CO2 and / or H2S is less than the hydraulic pressure of the water (and therefore remains in solution) when the water is transferred downwards ensures that the gas remains dissolved in the water and does not degas from the water. The method of the present invention therefore minimizes the risk of bubbles rising from the water, which would otherwise mean that the CO2 and / or H2S would not be effectively transferred to the geological reservoir where the gas would be absorbed and / or mineralized.

[0034] At the same time, the low pH of the water promotes the dissolution of minerals in geological reservoirs, thereby providing the cations required for carbon and sulfur mineralization and emission reduction.

[0035] Since the pressure of CO2 and / or H2S before injection into the water is greater than the hydraulic pressure of the water, bubbles will be present in the water at the merging point (i.e. the gas injection point), but since the bubbles are transferred downward at the critical water velocity, the gas flow is ensured to dissolve in the water and remain dissolved, i.e. remain in solution.

[0036] In one embodiment, the step of dissolving the gas in the water comprises directing the CO2 and / or H2S gas through an injection pipe having an open end extending downwardly into the injection well at a selected depth such that the hydraulic pressure of the water in the injection well at the open end of the injection pipe is less than the pressure of the CO2 and / or H2S gas in the injection pipe, while ensuring that the water is transferred downwardly at a velocity relative to the point where the gas is injected into the injection well, which ensures that for a given sub-portion of the water flow, relatively soon after the gas is injected into the water, the hydraulic pressure of the water is greater than the pressure of the dissolved CO2 and / or H2S. Thus, the hydraulic pressure required for both dissolving the CO2 and / or H2S gas in the water and maintaining the CO2 and / or H2S gas in solution in the water is obtained by transferring the water and gas to an appropriate depth or depths, and thus no external energy is required to obtain or maintain the required hydraulic pressure both at and below the merger point. Furthermore, the method according to the invention ensures that when CO2 and / or H2S is injected into the injection well at the open end (which is possible due to the hydraulic pressure in the injection pipe being greater than the hydraulic pressure in the injection well), it will not start to "effervesce" after injection, but will remain in a dissolved state, i.e. in solution, for the required time frame for the CO2 and / or H2S mineralizing water-rock reaction to occur. This is similar to avoiding a situation that might otherwise occur when a bottle of soda water is opened and carbon dioxide starts to bubble and thereby releases carbon dioxide from the bottle into the atmosphere. Thus, if the bottle is opened at an ambient pressure equal to or higher than the pressure in the bottle, such carbon dioxide bubbling will not occur. Furthermore, in the method according to the invention, the low pH of the water, due to the presence of dissolved CO2 and / or H2S therein, promotes the dissolution of minerals in the geological reservoir, thereby providing the cations required for carbon and sulfur mineralization and emission reduction.

[0037] In one embodiment, the step of dissolving CO2 and / or H2S gas in water includes directing CO2 and / or H2S gas through an injection pipe having an open end extending downwardly to the injection well, wherein the injection pipe is surrounded by an outer pipe having an open end positioned at a depth deeper than the open end of the injection pipe, and pumping water into the space between the outer pipe and the injection pipe is performed, and the depth at the injection pipe opening within the outer pipe is selected so that the hydraulic pressure of the water in the outer pipe at the open end of the injection pipe is less than the CO2 and / or H2S gas pressure in the injection pipe, while ensuring that the water is transferred downwardly at a speed relative to the point where the gas is injected into the injection well, which ensures that for a given sub-portion of the water flow, the hydraulic pressure of the water 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.

[0038] In one embodiment, the pumping rate of the water and the diameter of the pipe are selected so that the drag of the water flowing downwards to the injection well is greater than the buoyancy on the CO2 and / or H2S. Thus ensuring that a constant downwardly flowing water flow is provided ensures that the dissolved CO2 and / or H2S will move downwards and towards the reservoir reservoir. A method or system with relatively small gas bubbles (e.g. less than 6 mm in diameter) will require a minimum water velocity of between 0.4 m / s and 1.4 m / s according to the present invention, depending on the dynamic forces in the system.

[0039] In one embodiment, the pressure of the CO2 gas at the open end of the injection pipe (i.e., where the hydraulic pressure of the water in the injection well is less than the pressure of the CO2 gas in the injection pipe) is between 20-35 bar. At this pressure, the temperature of the water can be, but is not limited to, between 20-40°C, resulting in a single fluid phase entering the storage formation, which consists of, for example, relatively fresh basaltic lava.

[0040] In one embodiment, the depth at the open end of the outer tube is selected so that the pH of the injected water containing dissolved CO2 is between 2 and 4, preferably between 2.5 and 3.5, more preferably about 3.2. It is at this depth that the dissolved CO2 and / or H2S leave the outer tube and the sequestration of CO2 and / or H2S in the rock begins, i.e. the carbon dioxide CO2 and / or hydrogen sulfide H2S is stored in the geological reservoir. The lower the pH value, the faster the dissolution rate of the rock will be, which means that at such low pH values, the sequestration of carbon dioxide CO2 and / or hydrogen sulfide H2S in the reservoir reservoir will be significantly enhanced.

[0041] In one embodiment, the step of dissolving the CO2 and / or H2S gas in the water further comprises mixing the dissolved CO2 and / or H2S with the water at or below the merging point, such as by a bubbler and / or mixer, so as to obtain a uniform mixing of the CO2 and / or H2S gas in the water, breaking up larger bubbles and dissolving any remaining CO2 and / or H2S bubbles in the water. Thus, more turbulence will be created in the mixture of CO2 and / or H2S gas and pressurized water, which will further enhance the dissolution of the CO2 and / or H2S gas at and / or below the merging point. Likewise, large CO2 and / or H2S bubbles will break up into smaller bubbles, which will also enhance the dissolution of the CO2 and / or H2S.

[0042] In one embodiment, the water source is selected from one or more of the following: surface water, groundwater or seawater.

[0043] In one embodiment, the step of dissolving CO2 gas with the water further comprises maximizing the interfacial area between CO2 and / or H2S gas and water. Thus, CO2 and / or H2S bubbles will be equally distributed in the pressurized water, and further the average diameter of the bubbles will be reduced, causing the interfacial area between the CO2 and / or H2S gas and water to be maximized, wherein these two factors significantly increase the dissolution rate of CO2 and / or H2S in pressurized water.

[0044] In one embodiment, the step of dissolving the CO2 and / or H2S gas in the water further comprises mixing the dissolved CO2 and / or H2S with the water so as to obtain a uniform mixture of the CO2 and / or H2S gas in the water and dissolve any remaining CO2 and / or H2S bubbles in the water. Thus, more turbulence will be created in the mixture of CO2 and / or H2S gas and pressurized water, which will further enhance the dissolution of the CO2 and / or H2S gas. Likewise, large CO2 and / or H2S bubbles will break into smaller bubbles, which will also increase the dissolution rate of the CO2 and / or H2S.

[0045] In one embodiment, the step of dissolving CO2 and / or H2S gas in the water comprises directing the CO2 and / or H2S gas through an injection pipe having an open end extending downwardly into the injection well at a selected depth, such that the hydraulic pressure of the water in the injection well at the open end of the injection pipe is less than the pressure of the CO2 and / or H2S gas in the injection pipe, while ensuring that the water moves downwardly at a speed relative to the point where the gas is injected into the injection well, which ensures that for a given sub-portion of the water flow, relatively soon after the gas is injected into the water, the hydraulic pressure of the water is greater than the partial pressure of the dissolved CO2 and / or H2S. The hydraulic pressure is slightly less than the gas pressure at the depth of the merger point, firstly to ensure that the CO2 and / or H2S gas can enter the water of the injection well at the depth of the merger point, and secondly, that the hydraulic pressure of the water at a slightly greater depth is greater than the pressure of the CO2 and / or H2S after being dissolved in the water and moving downwardly at a given downward speed. Thus, by selecting the depth of the consolidation point in the injection well and the downward velocity of the water, it is ensured that the CO2 and / or H2S bubbles from the open end of the injection pipe will dissolve in the water within a very short time frame and remain dissolved in the water prior to the mineralization process within the geological reservoir. At the same time, the low pH of the water caused by the addition of CO2 and / or H2S gas promotes the dissolution of minerals in the geological reservoir, thereby providing the cations required for carbon and sulfur mineralization and emission reduction.

[0046] In one embodiment, the method further comprises the step of estimating the mineralization capacity of CO2 and / or H2S, wherein the step of estimating this comprises:

[0047] in addition to said CO2 and / or H2S, a tracer substance is dissolved in the water, the concentrations of dissolved CO2 and / or H2S and dissolved tracer substance being carried out in a controlled manner so that the initial molar ratio between CO2 and / or H2S and tracer substance is predetermined,

[0048] monitoring the molar ratio of CO2 and / or H2S to the tracer substance in a monitoring well in response to injecting the CO2 and / or H2S and the dissolved tracer substance, the monitoring well being a well interconnected to the injection well by a flow path such that at least a portion of the injected water mixed with the dissolved CO2 and / or H2S and the tracer substance flows to the monitoring well via the flow path, the monitoring comprising measuring the concentrations of CO2 and / or H2S and the tracer substance and the molar ratio of CO2 and / or H2S to the tracer substance in the monitoring well based thereon, and

[0049] Determining a reduction index indicative of the amount of CO2 and / or H2S reduction achieved through the water-rock reaction, the determination being based on comparing the molar ratio between CO2 and / or H2S and the tracer substance in the monitoring well with the corresponding molar ratio in the injection well at the merge point.

[0050] Based on such measurements, it can be determined whether the geological reservoir in question has the capacity to store in mineral form the CO2 and / or H2S injected through the injection well.

[0051] Regarding CO2, the tracer substance may be, but is not limited to, SF5CF3 tracers, SF6 or rhodamine tracers (all conservative tracers) or C-14 tracers that only trace carbon. One or more of these tracers may be used simultaneously.

[0052] Similarly, whether a geological system (such as in Iceland) has the ability to mineralize H2S through water-rock reactions can be determined by using tracer substances (such as but not limited to iodide ions) by dissolving KI in pressurized water.

[0053] In one embodiment, the method further comprises correcting the reduction index to take into account the oxidation of H2S and other sulfide species. This will therefore make the estimation of the reduction capacity more accurate. The correction can be performed by analyzing other types of sulfur in the groundwater from the injection well, comparing them with the values ​​obtained before the injection of H2S, and accounting for the excess sulfur species (e.g., SO4) formed by the oxidation of H2S before calculating the H2S reduction index. 2- and S2O3 - ) is added to the H2S value.

[0054] In one embodiment, the interconnection between the injection well and the monitoring well is a fracture in a geological reservoir.

[0055] In one embodiment, the method further comprises providing a constriction at the open end of the injection pipe so as to maintain a high hydraulic pressure in the injection pipe so as to further ensure that the CO2 and / or H2S gas will remain dissolved in the injection water.

[0056] In a second aspect of the present invention, a system for reducing CO2 and / or H2S emissions is provided, comprising:

[0057] · Devices for pumping water from a source to an injection well,

[0058] Device for pumping CO2 and / or H2S gas to injection wells

[0059] a device for dissolving CO2 and / or H2S in water in an injection well at a depth h1 ≥ 0, wherein the hydraulic pressure of the water is lower than the pressure of the CO2 and / or H2S,

[0060] means for transferring the water flow from the depth h1≥0 to a deeper depth h1+h2, wherein h1+h2>h1, with a downward flow velocity greater than the upward flow velocity of the bubbles of CO2 and / or H2S gas (caused by the buoyancy on the bubbles of CO2 and / or H2S gas in the water),

[0061] means for maintaining the resulting pH of said pressurized water stream comprising said dissolved CO2 and / or H2S at between about 2 and 4, preferably between about 2.5 and 3.5, more preferably at about 3.2, and

[0062] - Means for injecting water comprising said dissolved CO2 and / or H2S into a geological reservoir.

[0063] In one embodiment, the device for dissolving CO2 and / or H2S gas in water includes an injection pipe for guiding high-pressure CO2 and / or H2S gas into an injection well, the injection pipe having an open end extending downward to the injection well at a selected depth h1≥0, so that the hydraulic pressure of the water in the injection well at the open end of the injection pipe is less than the CO2 and / or H2S gas pressure in the injection pipe, and a pump device makes the downward flow rate of the water greater than the upward flow rate of the bubbles of the CO2 and / or H2S gas at a depth higher than h1, thereby ensuring that the water is transferred to a depth higher than h1 without CO2 and / or H2S escaping from the water.

[0064] In one embodiment, the system further comprises an outer tube surrounding the injection tube, the outer tube having an open end extending downwardly to the injection well at a further depth h1+h2, the means for pumping being a water pump for pumping water into the space between the outer tube and the injection tube, the means for injecting dissolved CO2 and / or H2S into the geological reservoir being the downward flow rate and resulting flow rate of water formed by pumping water into the space between the outer tube and the injection tube. In the case where the gas is limited to CO2, h1+h2 may be selected such that the pH of the injected water containing dissolved CO2 is below a predetermined pH limit.

[0065] In one embodiment, the apparatus for dissolving CO2 and / or H2S with water further comprises:

[0066] a bubbler mounted at said open end of the gas injection tube, adapted to maximise the interfacial area between the CO2 and / or H2S gas and the water, or

[0067] 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 the CO2 and / or H2S with the water so as to obtain a homogeneous mix of the CO2 and / or H2S in the water and to dissolve any remaining bubbles of CO2 and / or H2S gas in the water, or

[0068] a bubbler mounted at said 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 mounted within said outer tube between said bubbler and said open end of the outer tube, adapted to mix the CO2 and / or H2S with the water so as to obtain a homogeneous mix of the CO2 and / or H2S in the water and to dissolve any remaining CO2 and / or H2S bubbles in the water.

[0069] Thus, a practical and cost-effective system for in situ carbonation of minerals in reactive rocks (e.g., basalt) is provided, which injects water having sufficiently high concentrations of dissolved CO2 and / or H2S concentrations to favor reaction with the reactive rocks (e.g., basalt). Similarly, the low pH of the water promotes dissolution of minerals in the geological reservoir, thereby providing the cations required for carbon and sulfur mineralization and abatement.

[0070] In the method according to the invention, once dissolved, CO2 and / or H2S are no longer buoyant, which significantly improves safety due to the reduced risk of leakage. The injection of dissolved CO2 and / or H2S also promotes the carbonization of the host rock, thereby promoting safe long-term storage of CO2 and / or H2S underground.

[0071] It should be noted that the term water according to the present invention may mean fresh water, water from geothermal wells, salt water, seawater, etc. Therefore, the water source may be any type of water. Likewise, CO2 and / or H2S gas may originate from any source, such as conventional power plants, geothermal power plants, industrial production, gas separation stations, etc.

[0072] In general, the various aspects of the invention may be combined and coupled in any possible way within the scope of the invention.These and other aspects, features and / or advantages of the invention will become apparent and elucidated with reference to the embodiments described hereinafter. BRIEF DESCRIPTION OF THE DRAWINGS

[0073] Several embodiments of the present invention are described below, by way of example only, with reference to the accompanying drawings, in which

[0074] Figure 1 A flow chart of a method for reducing CO2 and / or H2S emissions in a geological reservoir according to the present invention is shown.

[0075] Figure 2 Schematic diagram showing the interaction between host rock and formation fluids during in situ CO2 mineral sequestration.

[0076] Figure 3 A flow chart showing an embodiment of the method according to the invention is shown, illustrating in more detail how dissolved CO2 and / or H2S are injected into a geological reservoir.

[0077] Figure 4 A system for storing carbon dioxide (CO2) in a geological reservoir according to the present invention is shown.

[0078] Figure 5 A flow chart showing an embodiment of a method for reducing hydrogen sulfide (H2S) emissions in a geological reservoir according to the present invention is shown.

[0079] Figure 6 A method according to the invention is schematically depicted showing an injection well wherein water is continuously pumped into the well.

[0080] Figure 7The downward flow rate (m / s) of water entering an injection well is shown as a function of the diameter of spherical (upper line) and elongated (lower line) bubbles, with buoyancy and downward drag being in equilibrium at a given temperature, pressure and gas and water composition. The shaded area represents bubbles having a form intermediate between spherical and elongated. It is clear from this figure that an apparatus capable of producing small bubbles will result in a method or system according to the invention being able to operate (i.e. at least in equilibrium) at relatively low flow rates (e.g. below 0.4 m / s), whereas an apparatus limited to larger bubbles will require an apparatus capable of providing higher flow rates (e.g. above 0.8 m / s) in order to be able to provide a method or system according to the invention (i.e. in equilibrium).

[0081] Figure 8 Shows Figure 7 A magnified view of the front quarter.

[0082] Figure 9-11 Various embodiments of a system for abatement of hydrogen sulfide (H2S) and carbon dioxide (CO2) in a geological reservoir according to the present invention are schematically depicted. DETAILED DESCRIPTION

[0083] Figure 1 A flow chart of a method for reducing CO2 and / or H2S in a geological reservoir according to the invention is shown. The term geological reservoir may be understood as fractures in hot rock that expand in directions other than upwards and downwards and provide flow paths for injection water from a well.

[0084] In the first step (S1) 101, water is pumped from a water source to an injection well. The water source may be, but is not limited to, underground hot water, salt water, etc., or may be fresh water and sea water. For simplicity, the term "water" will be used hereinafter. Furthermore, the temperature of the water may range from only a few degrees Celsius up to several hundred degrees.

[0085] In a second step (S2) 103, the CO2 and / or H2S gas is combined with the water at a combination point where the hydraulic pressure of the water is lower than the pressure of the CO2 and / or H2S, while ensuring that the water is transferred downwardly at a velocity relative to the point where the gas is injected into the injection well, which ensures that for a given sub-portion of the water flow, the hydraulic pressure of the water is greater than the partial pressure of CO2 and / or H2S relatively soon after the gas is injected into the water.

[0086] In step (S3) 105, water with dissolved CO2 and / or H2S is injected into a geological reservoir.

[0087] In one embodiment, step (S2) 103 includes directing CO2 and / or H2S gas through an injection pipe having an open end extending downwardly into the injection well at a selected depth h1≥0, so that the hydraulic pressure of the water in the injection well at the open end of the injection pipe is less than the CO2 and / or H2S gas pressure in the injection pipe. This is only to enable the CO2 and / or H2S gas to flow into the water at a depth h1≥0. At the same time, a downward flow rate of water is provided that is higher than the upward flow rate of the bubbles of the CO2 and / or H2S gas at a depth greater than h1, thereby ensuring that the water is transferred to a depth deeper than h1 without CO2 and / or H2S escaping from the water.

[0088] In a preferred embodiment, the CO2 gas pressure at the open end of the injection pipe is between 20-35 bar. This large pressure ensures that the pH value of the water containing dissolved CO2 is relatively low, which will enhance the CO2 water-rock reaction in the geological reservoir.

[0089] One of the important aspects of the present invention is that CO2 (and / or H2S) is dissolved in water and then dispersed into the pore space of the reactive rock formation as a single-phase fluid. According to the following, CO2 dissolves to form carbonic acid (H2CO3), which can decompose into bicarbonate (HCO3) and carbonate (CO 2 3 - ):

[0090] CO 2(g) =CO 2(水溶液) (1a)

[0091] CO 2(aq) +H2O=H2CO 3(水溶液) (1b)

[0092]

[0093] For example, plagioclase ((Ca,Na)Al 1.70 Si 2.30 O8), olivine ((Mg,Fe)2SiO4), and pyroxene ((Ca,Mg,Fe)2SiO3) are the most abundant primary minerals in basalt, but basalt glass is also common. When the minerals and glass come into contact with injected acidic fluids, dissolution reactions occur, leaching cations such as Ca from the rock matrix. 2+ Mg 2+ and Fe 2+ Reactions 2-5 below show the dissolution of plagioclase, olivine, pyroxene and basalt glass, respectively. The composition of the basalt glass in reaction 5 is that of the Stapafell glass as reported in the scientific literature by Oelkers and Gislason (reference 11).

[0094] (Ca,Na)Al 1.70 Si 2.30 O 8(s) +6.8H + =(Ca 2+ ,Na + )+1.70Al 3+ +2.3SiO 2(水溶液) +3.4H2O (l) (2)

[0095] (Mg,Fe)2SiO 4(s) +4H + =2(Mg,Fe) 2+ +SiO 2(水溶液) +2H2O (l) (3)

[0096] (Ca,Mg,Fe)2SiO3+2H + =2(Ca,Mg,Fe) 2+ + SiO 2(aq) +H2O (l) (4)

[0097] SiAl 0.36 Fe 0.19 Mg 0.28 Ca 0.26 Na 0.08 K 0.008 O 3.31 +2.58H + =SiO 2(水溶液) +0.36Al 3+

[0098] +0.19Fe 2+ +0.28Mg 2+ +0.26Ca 2+ +0.08Na + +0.008K 2+ +1.30H2O (l) (5)

[0099] As dissolution reactions 2-5 proceed underground after CO2 and / or H2S injection, protons (H + ) is consumed and the pH of the formation fluid increases.

[0100] As water flows from the injection well, the concentration of leached cations increases, e.g. Figure 2 As shown, it shows a schematic diagram of the interaction between host rocks and formation fluids during in situ CO2 mineral sequestration after CO2 is injected into injection well 2000. Figure 2The left side shows a depth scale extending to below 800 m. Arrows 2005-2007 indicate the direction of regional groundwater flow and different distances from the injection well 2000, where at arrow 2005, the water next to the injection well 2000 may be weakly acidic, where a single-phase fluid enters the formation and leaches cations out of the rock matrix. At a greater distance 2006 from the injection well, ion concentrations increase as rock dissolution proceeds and the pH of the water increases. At a greater distance 2007 from the injection well, mineral supersaturation and precipitation occur, where clays and zeolites compete with carbonates for dissolved cations.

[0101] At certain concentrations, water becomes supersaturated with respect to secondary minerals such as carbonates, which begin to precipitate according to reaction 6:

[0102] (Ca, Mg, Fe) 2+ + CO 2 3 - = (Ca, Mg, Fe)CO 3(s) (6)

[0103] Calcite (CaCO3), dolomite (CaMg(CO3)2), magnesite (MgCO3), and siderite (FeCO3) are suggested carbonate-forming minerals. It is difficult to predict in advance which of these carbonates will actually precipitate in the subsurface during CO2 injection, and to what extent they will form. Other minerals such as clays, hydroxides, and zeolites may also form and compete with reaction 6 for leached cations.

[0104] Figure 3 A flow chart showing an embodiment of the method according to the present invention indicates in more detail how said step (S3) 105 is performed.

[0105] In step (S3') 201, the hydraulic pressure of the water pumped from the water source is increased to form pressurized water. This can be done, for example, by pumping water from the water source to the injection well via a pipeline, wherein the pressure in the pipeline is increased, for example, by appropriate equipment such as a water pump, so that the pressure can be controlled and adjusted to the pressure of the CO2 and / or H2S gas to be dissolved.

[0106] In step (S3") 203, CO2 and / or H2S gas is dissolved with pressurized water, wherein the hydraulic pressure of the water is selected so that the hydraulic pressure of the water is less than the pressure of the CO2 and / or H2S gas during gas dissolution. In one embodiment, the pressure of the water is about 6 bar or slightly less than the pressure of the CO2 and / or H2S gas. In this embodiment, the step (S3) 105 of injecting the dissolved H2S into the geological reservoir is carried out through an injection pipe having an open end extending downwardly to the injection well at a depth h1≥0, the depth h1 being below the surface level of the water in the injection well. The depth is preferably selected so that the hydraulic pressure of the water in the injection well at the position where the open end of the injection pipe is located in the well is less than the hydraulic pressure of the water in the injection pipe, but is greater than the hydraulic pressure of the dissolved H2S at a slightly deeper depth h2 reached when the water flows downwardly. The reason for this is to ensure that when the water with dissolved CO2 and / or H2S comes out of the open end of the injection pipe, the surrounding pressure will be greater than the pressure of the dissolved CO2 and / or H2S. By doing this, the dissolved CO2 and / or H2S will remain dissolved until the CO2 and / or H2S mineralization water-rock reaction begins. At the same time, the low pH of the water containing dissolved CO2 and / or H2S promotes the dissolution of minerals in the geological reservoir, thereby providing the cations required for carbon and sulfur mineralization and emission reduction. This gas dissolution process can be promoted by using appropriate equipment, which maximizes the interfacial area between the H2S gas and the water and / or mixes the dissolved H2S with the water in order to obtain a uniform mix of the H2S in the water and dissolve any remaining H2S bubbles in the water.

[0107] In one embodiment, the step (S3) 105 of dissolving CO2 and / or H2S gas in water includes guiding CO2 and / or H2S gas through an injection pipe having an open end extending downward into the injection well at a selected depth h1≥0, so that the hydraulic pressure of the water in the injection well at the open end of the injection pipe is less than the pressure of CO2 and / or H2S gas in the injection pipe. Preferably, the hydraulic pressure at the open end is slightly less than the pressure of CO2 and / or H2S gas in the pipeline, firstly to ensure that CO2 and / or H2S gas can enter the water in the injection well, and secondly, after having entered the water at a depth h1≥0 and having moved downward some distance with the water flow, the hydraulic pressure at the deeper depth h1+h2 (i.e. after CO2 and / or H2S has moved downward a distance h2) is greater than the pressure of CO2 and / or H2S dissolved in the water. The injection pipe can be, for example, a pipe extending from a gas separation station, where CO2 and / or H2S gas is separated from geothermal gas and then guided to the injection well through a pipeline.

[0108] Figure 4An embodiment of a system 200 for storing carbon dioxide CO2 in a geological reservoir 201 according to the present invention is schematically depicted. The system includes a CO2 gas pipeline 202, a wellhead 209, a water inlet 203, a gas injection pipe 206, a bubbler 207, a mixer 208, and an external water injection pipe 204. CO2 is guided to the wellhead 209 and enters an injection well 210 under high pressure through the gas injection pipe 206 having an open end at a depth h1≥0, but the injection pipe 206 is surrounded by an external water injection pipe 204 having an open end at a depth h1+h2. In this embodiment, the amount of water (liters / second) pumped to the injection well 210 is controlled by a valve 211, wherein the water is pumped to the space between the injection pipe 206 and the external water pipe 205.

[0109] The depth of the opening of the injection pipe at the depth h1 ≥ 0 is chosen so that the hydraulic pressure of the water at this depth is slightly less than the pressure of the CO2 gas in the injection pipe. This is to ensure that the CO2 gas can enter the water. Further down the CO2 gas is injected into the water, i.e. at a depth h1 + Δh, where Δh < h1, the hydraulic pressure of the water is greater than the pressure of the dissolved CO2. This is to ensure that the pressure of the dissolved CO2 is less than the hydraulic pressure so that it remains dissolved in the water.

[0110] The water flow rate to the space between the injection tube 206 and the outer tube 204 is selected so that the water flow rate indicated by the arrow is greater than the upward velocity of the CO2 bubbles (caused by the buoyancy on the CO2 gas at the open end of the injection tube). Therefore, as the CO2 bubbles move downward, the hydraulic pressure increases, the CO2 dissolves into the water and the bubbles become smaller, resulting in a decrease in the upward velocity of the bubbles. The preferred condition is when the bubbles are smaller, because at this time the upward travel velocity of the bubbles is smaller, and the total surface area is also larger, resulting in an increased dissolution rate.

[0111] One way to analyze the water flow rate required to prevent a spherical bubble from rising from the injection tube down the tube is to calculate when the buoyancy of a bubble with the density of a carbon dioxide bubble (in the form of a perfect sphere) at the relevant pressure and temperature is equal to the drag force of the water at the downward flow rate. Under these conditions, the spherical bubble will be stationary. If the flow rate is small, the bubble will travel upward, and if the flow rate is high, the bubble will travel downward with the water flow. The calculation results are shown in Figure 1. Figure 7 and 8As shown. The horizontal axis represents the downward flow velocity of the water in m / s, and the vertical axis represents the bubble diameter in mm. Since the bubbles are not solid spheres, they may deform and become oblate spheroids in the flowing medium. This is especially applicable to larger bubbles, because surface tension will keep smaller bubbles more spherical. A method or system operating with relatively small bubbles (e.g., less than 6 mm in diameter) will be able to operate at relatively low flow velocities (e.g., less than 0.4 m / s) according to the present invention, while a method or system using relatively large bubbles (e.g., greater than 20 mm in diameter) will be able to operate at relatively high flow velocities (e.g., greater than 0.8 m / s) according to the present invention.

[0112] Return to reference Figure 4 , a bubbler 207 is placed at the open end of the injection tube 206 to maximize the interface area between the CO2 gas and the water. By doing so, the CO2 bubbles will be equally distributed in the water, and further, the average diameter of the bubbles will be reduced, causing the interface area between the CO2 gas and the water to be maximized.

[0113] Below the bubbler is a mixer 208, whose function is to mix the dissolved CO2 with the water so as to obtain a uniform mix and dissolve any remaining CO2 bubbles in the water. Thus, more turbulence will be created, which will further promote the dissolution of the CO2 gas. Likewise, large CO2 bubbles will break into smaller bubbles, which will also increase the dissolution rate of the CO2.

[0114] In one embodiment, the depth h1 of the water column in the outer tube is about 250m, which means that the hydraulic pressure becomes 24.5 bar. This means that the pressure of the CO2 gas is slightly greater than 24.5 bar. As long as it leaves the open end of the injection pipe 206 and passes through the bubbler 207, it will be dispersed into small bubbles and then dissolved in water. Due to the constant water flow entering the space between the injection pipe and the outer tube 204, a vertical downward speed is generated, causing the dissolved CO2 to move toward the open end of the injection pipe at the depth h1+h2. The depth is preferably selected so that the pH value of the dissolved CO2 is about 3.2, but the pH value decreases as the CO2 pressure increases. This corresponds to h1+h2≈520m. It is at this depth that the dissolved CO2 leaves the system 200 and the sequestration of CO2 in the basalt begins. The lower the pH value, the higher the dissolution rate in the basalt.

[0115] An additional advantage of the present invention is its cost relative to conventional technologies. The overall "field cost" for capturing, transporting and storing this gas mixture at the CarbFix2Hellisheiei site is $24.8 / ton of gas mixture CO2 / H2S. This is significantly lower than the prices reported by others ($35 to $143 / ton CO2) (Reference 12: Global CCS Institute; Reference 13: Rubin et al; Reference 14: HU and Zhai; Reference 16: Sigfusson et al; Reference 17: Gunnarsson et al). This study demonstrates the efficiency and cost advantages of capturing and storing mixed dissolved gas streams at deep geological sites.

[0116] Although the present invention has been described and illustrated in detail in the drawings and the foregoing description, such description and illustration should be considered illustrative or exemplary rather than restrictive; the present invention is not limited to the disclosed embodiments. By studying the drawings and the disclosure, those skilled in the art can understand and implement other changes to the disclosed embodiments when practicing the claimed invention.

[0117] With reference to the accompanying drawings, the present invention particularly relates to a method for reducing carbon dioxide (CO2) and / or hydrogen sulfide (H2S), comprising the following steps:

[0118] pumping or transferring water from a water source into an outer pipe (205) of an injection well (210), thereby creating a pressurized water flow in said outer pipe (205),

[0119] Pumping the CO2 and / or H2S-rich gas into the gas injection pipe (206) of the injection well (210), thereby generating a CO2 and / or H2S-rich gas flow comprising pressurized CO2 and / or pressurized H2 in the injection pipe (206);

[0120] dissolving substantially all of the pressurized CO2 and / or H2S gas of the CO2 and / or H2S-rich gas stream in the pressurized water stream by merging the pressurized water stream and the CO2 and / or H2S-rich gas stream at a depth h1 ≥ 0, wherein the hydraulic pressure of the water in the outer pipe (205), p(W), is lower than the pressure of the CO2 and / or H2S in the injection pipe (206), p(C) and / or p(H)

[0121] maintaining the dissolved CO2 and / or H2S in solution in the water stream by transferring the water stream from the depth h1≥0 to a depth h1+h2 at a downward flow velocity, v(W), wherein (h1+h2)>h1, at which v(W) is greater than the upward flow velocity of the CO2 and / or H2S gas, v(C) and / or v(H), which is caused by the buoyancy on bubbles of CO2 and / or H2S gas in the water stream at the depth h1+h2

[0122] - Injecting said pressurized water stream comprising dissolved CO2 and / or H2S into a geological reservoir comprising reactive rocks at h1+h2 or at a depth > (h1+h2).

[0123] In a particularly preferred embodiment of the method according to the invention, the geological reservoir is a geothermal reservoir.

[0124] In a particularly preferred embodiment of the method according to the invention, the interfacial area between the CO2 and / or H2S to be dissolved in the water flow is increased by equipping the injection pipe (206) with a device (207) for bubbling at the merging point at depth h1.

[0125] 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, such as 300-600 m or 500-750 m.

[0126] In a further particularly preferred embodiment of the method according to the invention, said downward flow velocity of said water, v(W) is 0.5-1 m / s, such as 0.6-0.9 m / s, for example 0.65-0.85 m / s, such as 0.7 m / s.

[0127] In a further particularly preferred embodiment of the method according to the invention, the injection pipe (206) extends downwardly inside the outer pipe (205) comprising the pressurized water flow and has an open end at the depth h1 ≥0.

[0128] In yet another particularly preferred embodiment of the method according to the invention, said outer pipe (205) comprising said pressurized water flow has an open end at said depth hi+h2.

[0129] In yet another particularly preferred embodiment of the method according to the present invention, the CO2 pressure, p(CO2), at the merging point at a depth h1≥0 is between about 15-40 bar, such as 17-38 bar, for example 20-36 bar, preferably between about 22-34 bar, more preferably between about 24-32 bar, and most preferably about 24.5 bar.

[0130] In yet another particularly preferred embodiment of the method according to the present invention, the pressure of H2S at the merging point at a depth h1≥0, (pH) is between about 3-9 bar, such as between 4-8 bar, preferably between about 5-7 bar, more preferably between about 5.5-6.5 bar, such as between 5.6 and 6.4, for example between 5.7 and 6.3 bar, and most preferably about 6 bar.

[0131] In yet another particularly preferred embodiment of the method according to the present invention, the resulting pH value of the pressurized water stream comprising 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 3.2.

[0132] In yet another particularly preferred embodiment of the method according to the invention, the method further comprises the following steps:

[0133] dissolving a tracer substance in the pressurized water flow at the depth h1≥0 in the outer pipe (205) in the injection well (210 / 612) at a predetermined molar ratio compared to the dissolved CO2 and / or H2S,

[0134] establishing a monitoring well (610) interconnected with the outer pipe (205) of the injection well (210 / 612) via a flow path (614), so that 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),

[0135] measuring the concentrations of CO2 and / or H2S and the tracer substance at the monitoring well (610) and establishing a molar ratio between CO2 and / or H2S and the tracer substance at the monitoring well (610) based thereon, and

[0136] Determining an emission reduction index indicating the extent of CO2 and / or H2S emission reduction based on comparing the molar ratio between CO2 and / or H2S and the tracer substance at the monitoring well (610) with the predetermined molar ratio in the pressurized water flow at the depth h1 in the outer pipe (205) in the injection well (210 / 612).

[0137] With reference to the accompanying drawings, the present invention furthermore particularly relates to a system for reducing carbon dioxide (CO2) and / or hydrogen sulfide (H2S), comprising:

[0138] Injection wells (210)

[0139] An outer pipe (205) extending downwardly inside the injection well (210)

[0140] An injection pipe (206) extending downwardly inside the injection well (210)

[0141] means for pumping or transferring water from a water source into said outer tube (205) so as to generate a pressurized water flow in said outer tube (205),

[0142] means for pumping a gas rich in CO2 and / or H2S to said injection pipe (206) so as to produce in said injection pipe (206) a gas stream rich in CO2 and / or H2S comprising pressurized CO2 and / or pressurized H2

[0143] means for merging the pressurized water flow and the gas flow rich in CO2 and / or H2S at a depth h1≥0, wherein the hydraulic pressure of the water in the outer pipe (205), p(W), is lower than the pressure of the CO2 and / or H2S in the injection pipe (206), p(C) and / or p(H)

[0144] means for transferring the water flow from the depth h1≥0 to a depth h1+h2 at a downward flow velocity, v(W), wherein (h1+h2)>h1, at which v(W) is greater than the upward flow velocity, v(C) and / or v(H) of the CO2 and / or H2S gas, said v(C) and / or v(H) being caused by the buoyancy on the bubbles of CO2 and / or H2S gas in the water flow at the depth h1+h2

[0145] means for maintaining the resulting pH of said pressurized water stream comprising said dissolved CO2 and / or H2S between about 2 and 4, preferably between about 2.5 and 3.5, more preferably about 3.2

[0146] - Means for injecting said pressurized water stream comprising dissolved CO2 and / or H2S into a geological reservoir comprising reactive rocks at h1+h2 or at a depth > (h1+h2).

[0147] In a particularly preferred embodiment of the system according to the invention, the system further comprises means (207) for bubbling mounted on said injection pipe (206) at said merging point at a depth h1 ≥0.

[0148] 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, such as 300-600 m or 500-750 m.

[0149] In a further particularly preferred embodiment of the system according to the present invention, the device for transferring the water flow from the depth h1 to the depth h1+h2 is capable of providing a downward flow velocity of the water, v(W), wherein (h1+h2)>h1, v(W) is 0.5-1m / s, such as 0.6-0.9m / s, for example 0.65-0.85m / s, such as for example 0.7m / s.

[0150] In a further particularly preferred embodiment of the system according to the invention, the injection tube (206) extends downwardly into the outer tube (205) and has an open end at the depth h1 ≥0.

[0151] In a further particularly preferred embodiment of the system according to the invention, the outer tube (205) has an open end at the depth h1+h2.

[0152] In yet another particularly preferred embodiment of the system according to the invention, the system further comprises:

[0153] means for dissolving a tracer substance in the pressurized water flow at the depth h1≥0 in the outer pipe (205) in the injection well (210 / 612) at a predetermined molar ratio compared to the dissolved CO2 and / or H2S,

[0154] Monitoring wells (610)

[0155] a flow path (614) through which at least a portion of the pressurized water mixed with the dissolved CO2 and / or H2S and the tracer substance flows from the outer pipe (205) of the injection well (210 / 612) to the monitoring well (610),

[0156] means for measuring the concentration of CO2 and / or H2S and the tracer substance at the monitoring well (610) and establishing a molar ratio between CO2 and / or H2S and the tracer substance at the monitoring well (610) based thereon, and

[0157] Means for determining an emission reduction index indicating the extent of CO2 and / or H2S emission reduction based on comparing the molar ratio between CO2 and / or H2S and the tracer substance at the monitoring well (610) with the predetermined molar ratio in the pressurized water flow at the depth h1 in the outer pipe (205) in the injection well (210 / 612).

[0158] The methods and systems of the present invention can be further illustrated by the following examples.

[0159] Embodiment 1:

[0160] 0.07 kg / s of CO2 comes from the gas cleaning unit or gas separation station of the geothermal power plant. The initial pressure of the gas is 30 bar. To transport the gas to the injection well, a pipe with an outer diameter (OD) of 40 mm is selected, resulting in a pressure drop of 1.45 bar. Including other pressure losses, it is assumed that the wellhead pressure is 28 bar. For injection, a pipe with an OD of 32 mm is selected, resulting in a pressure drop of 0.41 bar, but due to gravity, the pressure head at the merger point will increase by 1.1 bar, and the pressure at the merger point will be 28.6 bar.

[0161] The injection pipe is a pipe of OD 75mm and requires a volume flow of 1.94kg / s of water to dissolve the gaseous carbon dioxide. The pressure drop under these conditions is 0.51 bar / 100m. Therefore, due to the pressure drop down to the merging point, the water column in the injection pipe will be about 13m higher than the water level in the well. There is no need to change the position of the merging point due to this increased pressure. However, due to the pressure drop in the pipe below the merging point, the water column in the pipe will rise further by about 15m, and therefore the merging point must be raised accordingly. Therefore, the water level will be about 28m higher than the water level in the well. To have a pressure of 25 bar at the merging point, it must be 255m lower than the water level in the pipeline or 227m lower than the water level in the well.

[0162] Under these conditions, the pressure drop at the merge can be up to 3.6 bar. The downward flow velocity of the water at the merge point will be about 0.95 m / s. Applying the same procedure with a lower water flow rate of 1.73 kg / s results in a downward flow velocity of 0.85 m / s at the merge point. However, this lower flow rate prevents the effective downward movement of all bubbles, resulting in premature shutdown of the process. If the inner diameter of the water pipe is reduced at the merge point, sufficient downward water flow velocity can be achieved even at a reduced water flow rate of 1.73 kg / s to ensure complete dissolution of the bubbles. Such a design will reduce the water demand of this gas abatement method.

[0163] Embodiment 2:

[0164] In this embodiment, the partial pressure of carbon dioxide is selected to be 25 bar downhole. This means saturation or 36g CO2 / kg water at 25 bar pressure at 17°C. At this temperature and pressure, the volume of carbon dioxide is about 20 times the volume of the same amount of water at atmospheric pressure. In order for the water to be able to pull the gas downward, the volume of the gas should not exceed the volume of the water, preferably much smaller. In order for the water to be able to carry the gas downward in the pipe, the hydraulic pressure at the gas release point (merging point) should preferably be close to the saturation pressure of 25 bar. However, if sufficient volumetric water flow is maintained, the pressure can be lowered. A portion of the gas will dissolve in the water, and the remaining gas will form small bubbles and travel down the pipe with the water. As the depth increases, the bubbles become smaller as the pressure increases, and the gas continues to dissolve in the water until all the gas is dissolved.

[0165] Embodiment 3:

[0166] In this embodiment, if Fig.10 As shown, the monitoring well 610 is interconnected with the injection well 612 by a flow path 614, which flow path can be, for example, a fracture in a geological reservoir. The implementation of the monitoring well 610 is to estimate the mineralization capacity of CO2. The estimation step includes tracing CO2 gas or water or carbon using one or more tracer substances. Therefore, one or more types of tracers can be added via an appropriate tracer source for tracing one or more of these in a controllable manner, so that the molar ratio between CO2 gas or water or carbon and one or more tracer substances is predetermined, that is, the molar ratio is pre-fixed. This means that only one tracer can be used for tracing, such as only CO2, or only C, or only water or a combination thereof. As an example, SF5CF3 tracers, SF6 tracers or rhodamine tracers can be used to trace the dilution between the injected fluid and the ambient water in the reservoir, and for characterizing the advection and diffusion transport of CO2 saturated solutions in the reservoir reservoir. On the other hand, the concentration of the C-14 tracer injected together with the CO2 changes due to the CO2-water-rock interaction and therefore allows the degree of mineralization of the injected CO2 to be estimated in the mass balance calculation. Monitoring equipment (not shown here) can be provided for monitoring the CO2 gas in the monitoring well 610, or the molar ratio between water or carbon and the tracer substance, as a result of the injection of the dissolved CO2. As already mentioned, the monitoring well 610 is interconnected with the injection well 612 by the flow path, so that at least a part of the injected water mixed with the dissolved CO2 and the tracer substance flows to the monitoring well 610 through the flow path 614. By comparing the molar ratio at the monitoring well 610 and the injection well 612, an emission reduction index indicating the amount of CO2 sequestered by the water-rock reaction can be determined. Therefore, if the tracer used is SF5CF3 tracer and the molar ratio between [SF5CF3] / [CO2] is 1 at the injection well 612, but 2 at the monitoring well 610, this will clearly indicate that half of the CO2 has chemically reacted with the rock through the water-rock reaction.

[0167] Such monitoring well 610 can also be connected with Figure 4 The embodiments shown are implemented in a related manner.

[0168] Embodiment 4:

[0169] Figure 5 An embodiment of a method for reducing hydrogen sulfide emissions in a geothermal reservoir according to the present invention is shown, wherein the mineralization capacity of H2S is estimated. Figure 1The method steps described in the method may occur before, or may be implemented as a monitoring method performed at a later time.

[0170] In step (S4) 301, in addition to dissolved H2S, a tracer substance such as KI is dissolved in a controlled manner such that the molar ratio of H2S to the tracer substance is predetermined.

[0171] In step (S5) 303, in response to injecting dissolved H2S and dissolved tracer substance into the injection well, the molar ratio between H2S and tracer substance in the monitoring well is monitored. The monitoring well is a well interconnected with the injection well by a flow path (e.g., a crack or fracture in the rock) so that at least a portion of the injected water mixed with the dissolved H2S and the tracer substance flows to the monitoring well through the flow path. The monitoring includes then measuring the concentration of H2S and tracer substance and the molar ratio between H2S and tracer substance at the monitoring well based thereon.

[0172] In step (S6) 305, a reduction index indicative of the amount of H2S reduction through water-rock reactions is determined based on comparing the molar ratio between H2S and the tracer material at the monitoring well with the corresponding molar ratio at the injection well. For example, if the H2S / tracer molar ratio entering the injection well is 1.0, but is 0.5 in the monitoring well, this would indicate that half of the dissolved H2S is mineralized in the geothermal reservoir through water-rock reactions. However, in order to further improve the method, it is preferred to perform a correction taking into account the oxidation of H2S to other sulfur species (which may lead to uncertainty).

[0173] Embodiment 5:

[0174] Figure 6 Schematically depicts Figure 5In the method of FIG. 4 , an injection well 400 is shown, wherein water 409 is continuously pumped into the well 400. The total depth of such a well can be several kilometers. As shown here, the well is partially filled with water, wherein the water surface 406 is close to the closed cap of the casing 401 of the injection well. Due to the continuous pumping of water, a water flow extending downward into the hole is formed in the well, and some of the water will flow into the geothermal reservoir 403 in the direction shown by the arrow 404. As depicted here, the injection well includes a casing 401 that seals the well, such as a steel pipe (for example, sealing the well relative to the underground fresh water above the geothermal reservoir). The height of such a casing 401 can be from a few hundred meters to more than 1000 meters. As shown here, the rest of the injection well is in the rock 402. The water-rock reaction occurring in the geothermal reservoir is represented in the expanded view of 404, showing the flow path of dissolved H2S in the rock, wherein the dissolved H2S chemically reacts with metal ions (Me) 407 in the rock and forms Me sulfide 408. If for example Me is Fe, then the Me sulfide will be a Fe-sulfide.

[0175] If the water source is a geothermal well, the temperature of the water 409 pumped into the well is typically about 100°C, but preferably it is cooler because less water is required to dissolve the H2S than hot water. However, this depends on the water source, i.e. whether a freshwater source (cold water) is used instead of a geothermal hot water source.

[0176] Embodiment 6:

[0177] Fig. 9 An embodiment of a system 500 for reducing the emission of hydrogen sulfide (H2S) in a geothermal reservoir 501 according to the present invention is schematically depicted. The system includes an H2S gas pipeline 502, a wellhead 509, a water inlet 503, an injection pipe 506, a bubbler 507, a mixer 508, and an outer pipe 504. H2S is guided to the wellhead 509 and into an injection well 510 under high pressure through an injection pipe 506 having an open end at a depth h1≥0, but the injection pipe 206 is surrounded by an outer pipe 504 having an open end at a depth h1+h2. In this embodiment, the volume flow rate (liters / second) of water entering the injection well 510 is controlled by a valve 511, wherein the water is pumped into the space between the injection pipe 506 and the outer pipe 505.

[0178] The depth of the opening of the injection pipe at depth h1 is selected so that the hydraulic pressure of the water at this depth is slightly less than the H2S gas pressure in the injection pipe. This is to ensure that the H2S gas can enter the water. Below the site where the H2S gas is injected, at a depth h1+Δh, where Δh<

[0179] ​The flow of water entering the space between the injection tube 506 and the outer tube 504 is selected so that the volumetric flow rate of the water and the resulting velocity (as indicated by the arrow) is greater than the velocity of the H2S gas pointing upward (due to the buoyancy on the H2S gas at the injection tube opening). Therefore, as the H2S bubbles move downward, the hydraulic pressure increases and the bubbles become smaller, resulting in a decrease in the velocity of the bubbles pointing upward. The preferred condition is when the bubbles are smaller because then the upward travel velocity of the bubbles is less and the total surface area is also larger, resulting in an increased dissolution rate.

[0180] In this embodiment, a bubbler 507 is placed at the open end of the injection tube 506 to maximize the interface area between the H2S gas and the water. By doing so, the H2S bubbles will be equally distributed in the water, and further, the average diameter of the bubbles will be reduced, resulting in the maximization of the interface area between the H2S gas and the water.

[0181] Below the bubbler is a mixer 508. The function of the mixer is to mix the dissolved H2S with the water so that the H2S gas is evenly mixed in the water and any remaining H2S bubbles are dissolved in the water. As a result, more turbulence will be created, which will further increase the dissolution rate of the H2S gas. Likewise, large H2S bubbles will break up into smaller bubbles, which will also increase the dissolution rate of the H2S.

[0182] Embodiment 7:

[0183] Fig.10 Another embodiment of a system 600 for reducing emissions, particularly hydrogen sulfide (H2S), in a geothermal reservoir according to the present invention is schematically depicted. In this embodiment, a monitoring well 610 is interconnected with an injection well 612 via a flow path 614, which may be, for example, a fracture in a geothermal reservoir. The monitoring well 610 is implemented to estimate the mineralization capacity of H2S, as previously described with respect to Figure 5 discussed.

[0184] Embodiment 8:

[0185] Fig.11 Yet another embodiment of a system 700 for reducing the emission of hydrogen sulfide (H2S) in a geothermal reservoir according to the present invention is depicted diagrammatically. In this embodiment, the H2S is transferred downward to an injection well 703 in a separate pipe 701 outside a water injection pipe 705. Since the pipe is fastened to the wellhead (not shown here), if conditions change, such as changes in water flow, the depth of the merging point will not change. Therefore, it is preferred to implement a pressure control valve 702 at the end of the injection pipe 705 to maintain a constant pressure at the merging point. The advantage of this solution is that the pressure drop in the injection pipe is low, and therefore a higher water flow rate can be maintained, which makes it easier to pull bubbles down the pipe.

[0186] Example 9 :

[0187] A large part of the safety risk associated with geological carbon storage is due to the ease with which gaseous CO2 escapes back to the surface and leaks into the atmosphere or into overlying freshwater aquifers. This is particularly problematic when attempting to store in porous geological formations.

[0188] The current set of experiments was conducted at the Hellisheidi geothermal power plant in Iceland. The rocks at the Hellisheidi injection site have an ultramafic to basaltic composition and are highly permeable in the lateral and vertical directions (300 and 1700 × 10 -15 m 2 ), and the porosity is estimated to be 8,5%.

[0189] use Figure 4 The device depicted in the figure has a load of 70 and 1940 g s -1 CO2 and H2O are injected at a target mass rate of 1.500 t / cm2. CO2 and H2O are released at a depth of 330-360 m. At this depth, CO2 is released into the flowing H2O in the form of small bubbles by a bubbler. The CO2 / H2O mixture is transmitted by a bubbler through a mixing pipe extending downward to 540 m and released into the underground rock there. Static mixers are placed about halfway (about 420 m) to help CO2 dissolve. In a 3-month period, about 175 t of CO2 is injected into the underground at the site together with about 5000 t of H2O.

[0190] Verification of complete dissolution of CO2 during injection was performed by a digital downhole camera (showing no CO2 bubbles) and by high pressure well water sampling using a custom made cartridge.

[0191] The image shows no bubbles in the well fluid, which is consistent with complete dissolution of CO2 at 1.5 m above the fluid outlet at 540 m.

[0192] Twelve well water samples were analyzed for total dissolved inorganic carbon, and the in situ pH was measured for six of the 12 well water samples. In each case, the dissolved inorganic carbon concentration of the sample fluid averaged within 5% of the concentration of 0.82 ± 2% mol / kg based on the measured CO2 and H2O mass flow rates entering the well, and the fluid pH was 3.89 ± 0.1, confirming that the CO2 was completely dissolved during injection.

[0193] Therefore, if injected into the subsurface as a dissolved phase, CO2 is unlikely to escape back into the atmosphere due to its lack of bubble formation or buoyancy (Reference 15: Gilfillan et al., 2009).

[0194] Embodiment 10:

[0195] Additional CO2 / H2S injection experiments were performed using the following parameters:

[0196]

[0197]

[0198] In this example, the partial pressures of carbon dioxide and hydrogen sulfide are selected to be 18 bar and 6 bar downhole.

[0199] The pH of water with dissolved CO2 decreases as the CO2 pressure increases, because this increases the CO2 content in the water. In one experiment, the depth was chosen so that the pH was about 3.2. This corresponds to a depth of 520 m. It is clear from the table above that the downward velocity of the water in this example was about 0.7 m / s. Changing the downward velocity of the water to about 0.3 m / s resulted in failure.

[0200] In this article, the word "comprising" does not exclude other elements or steps, and the indefinite article "a" or "an" does not exclude a plurality. A single processor or other device can implement the functions of multiple items stated in this article. The mere fact that certain measures are described in mutually different texts does not mean that a combination of these measures cannot be used advantageously. Any reference signs in this article should not be interpreted as limiting the scope.

[0201] References

[0202] All of which are incorporated herein by reference in their entirety.

[0203] Ref.1: Broecker WS, Kunzig, R., 2008. Fixing climate: what past climate changes reveal about the current threat–and how to counter it. Hill and Wang, New York; Oelkers, EH, Cole, D

[0204] Ref.2:Barbier,E.(2002)Geothermal Energy Technology and CurrentStatus:an Overview.Renewable and Sustainable Energy Reviews,6,p.3-65

[0205] Ref.3:Arnórsson,S.(1995a)Hydrothermal systems in Iceland:Structureand conceptual models.1.High-temperature areas.Geothermics 24,561-602Ref.4:Arnórsson,S.(1995b)Hydrothermal systems in Iceland:Structure and conceptualmodels.2.Low-temperature areas.Geothermics 24,603-629Ref.5:Kerr,T.M.,2007.Legal aspects of storing CO2:update and recommendations.OECD / IEA

[0206] Ref.6:Hawkins,D.G.,2004.No exit:thinking about leakage from geologiccarbon storage sites,Energy 29,1571–1578

[0207] Ref.7:Benson,S.M.,Cole,D.R.,2008.CO2 sequestration in deepsedimentary formations.Elements 4,325–331

[0208] Ref.8:Mineral sequestration of carbon dioxide in basalt:A pre-injection overview of the CarbFix project;Gislason SR,Wolff-Boenisch D,Stefansson A,et al.;INTERNATIONAL JOURNAL OF GREENHOUSE GAS CONTROL,Vol.4,Issue:3,Pages:537-545,Pub.May 2010

[0209] Ref.9:Sanopoulos,D.and Karabelas A.(1997).H2S abatement in geothermalplants:Evaluation of Process Alternatives.Energy Sources,19,63-77)

[0210] Ref.10:Hibara,Y.,Araki,K.,Tazaki,S.and Kondo,T.(1990)Recenttechnology of geothermal plants.Geothermal Resource Council Transactions 14,Part II:1015-1024

[0211] Ref.11:Oelkers,E.,Gislason,S.,2001.The mechamism,rates andconsequences of basaltic glass dissolution:I.an experimental study of thedissolution rates of basaltic glass as a function of aqueous al,si and oxalicacid concentrations at 25c and pH=3 and 11.Geochim.Cosmochim.Acta 65,3671–3681

[0212] Ref.12:Global CCS Institute(2011)Economic Assessment of CarbonCapture and Storage Technologies 2011 update Ref.13:Rubin et al.(2015)Int.J.Greenh.Gas Control 40,378–400

[0213] Ref.14:Hu and Zhai(2017)Int.J.Greenh.Gas Control 65,23–31

[0214] Ref.15:Gilfillan et al.(2009)Nature 458,614-618

[0215] Ref.16:Sigfusson et al.(2015)Int.J.Greenh.Gas Control 37,213–219Ref17:Gunnarson et al(2018)Int.J.Greenh.Gas Control 79,117–126。

Claims

1. A system for reducing carbon dioxide (CO2) and / or hydrogen sulfide (H2S) emissions in a geological reservoir, wherein: The system configuration is: Pumping or otherwise transferring water from a source to an injection well, Dissolving CO2 and / or H2S gas in the water by: o combining the CO2 and / or H2S rich gas stream and the water at a combining point to produce CO2 and H2S bubbles under conditions wherein the hydraulic pressure of the water is lower than the partial pressure of CO2 and / or H2S in the CO2 and / or H2S rich gas stream, and o ensuring that the CO2 and / or H2S remain dissolved in the water by transferring the water comprising CO2 and / or H2S downwardly from the merging point at a velocity greater than the upward velocity of the bubbles of CO2 and / or H2S gas in the water to a depth where the hydraulic pressure of the water has increased to the pressure required to dissolve all of the CO2 and H2S gas, maintaining the resulting pH of said pressurized water stream comprising said dissolved CO2 and / or H2S between about 2 and 4, • Injecting water comprising dissolved CO2 and / or H2S into the geological reservoir.

2. The system according to claim 1, wherein: The system comprises: Injection well a merging point for merging water from a water source with a gas stream rich in CO2 and H2S, means for controlling how much CO2 and / or H2S gas is dissolved in said water, and - Means for controlling the downward velocity of said water in said injection well.

3. The system according to claim 1 or 2, wherein: Transferring water comprising CO2 and / or H2S downwardly at a speed greater than the upward speed of bubbles of CO2 and / or H2S gas in the water comprises transferring water comprising CO2 and / or H2S downwardly at a speed of: o the velocity is a minimum of 0.4 m / s or less when the diameter of the bubbles of CO2 and / or H2S gas in the combined pressurized stream at the combining point is less than 6 mm, and o The velocity is greater than 0.8 m / s when the diameter of the bubbles of CO 2 and / or H 2 S gas in the combined pressurized flow at the combining point is greater than 20 mm.

4. The system according to claim 1 or 2, wherein: Maintaining the resulting pH of the pressurized water stream comprising the dissolved CO 2 and / or H 2 S between about 2 and 4 is based on how much CO 2 and / or H 2 S gas is dissolved in the water.

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