Patent Publication Number: US-2022219112-A1

Title: A method of abating carbon dioxide and hydrogen sulfide

Description:
FIELD OF THE INVENTION 
     The present invention relates to a method and a system for abating carbon dioxide (CO 2 ) and/or hydrogen sulfide (H 2 S) by injecting these into and subsequently storing these in a geological reservoir. 
     BACKGROUND OF THE INVENTION 
     Carbon dioxide (CO 2 ) and hydrogen sulfide (H2S) are two gasses often released in large quantities during a wide range of industrial processes, e.g. combustion of fossil fuels. Both gasses present important challenges to the environment. 
     The reduction of industrial CO 2  emissions is one of the main challenges of this century (Ref. 1: Broecker and Kunzig). In general, CO 2  emission is relatively low from geothermal resources and these are classified as renewable energy sources. This is in contrast to regular power plants that are run on fossil fuels which buy and sell pollution permits (called “allowances”). 
     Conventional geothermal plants utilize the heat of the Earth by making use of a hot mixture of steam and brine from a geothermal reservoir, characterized by a thermal anomaly, permeable rock, and fluid (Ref. 2: Barbier). The geothermal steam from these geothermal reservoirs naturally contains dissolved gases including both the greenhouse gas CO 2  and hydrogen sulfide (H 2 S). The gases are a by-product of the geothermal energy production and are of magmatic origin. When conventional geothermal plants are operated the gases in the steam are vented into the atmosphere. 
     Hitherto geothermal power plants have been exempted from buying CO 2  allowances as their greenhouse gas emission is fairly low. However, as climate change policy becomes stricter this might change and it is predicted that the price of emitting CO 2  will rise. 
     The emission of hydrogen sulfide from geothermal power plants is another of the main environmental concerns of geothermal utilization. Hydrogen sulfide is a colorless, flammable and toxic gas with the characteristic odor of rotten eggs. Exposure to it can cause health problems depending on levels and duration of exposure. Low level, prolonged exposure can cause inflammation and irritation of the eyes whereas high levels of exposure for brief periods of time can cause dizziness, headache, nausea and even death if the concentration of H 2 S in atmosphere goes above 300 ppm. 
     Concentration of hydrogen sulfide in geothermal fluids is usually in the range of few ppb to several hundred ppm (Ref. 3+4: Arnórsson). During utilization of high temperature geothermal fluids, the hydrogen sulfide is concentrated in the steam phase and subsequently released into atmosphere after the steam condenses. Annually e.g. the Hellisheiði power plant, which is in Iceland, emits 9500 tons of hydrogen sulfide into atmosphere without any abatement system in place. The hydrogen sulfide is released on top of the cooling towers to lower the risk of high concentration of hydrogen sulfide close to the power station. The hydrogen sulfide is carried by wind away from the site of the power plant and can under some weather conditions cause foul smell in nearby communities. 
     To date CO 2  has been stored e.g. as a supercritical fluid in association with major gas and oil production facilities such as Sleipner in the North Sea, In Salah, Algeria, and Weyburn, Canada (Ref. 5: Kerr). Regardless, the abatement of CO 2  in geological structures remains an attractive, although still relatively unexplored, possibility for reducing the amount of CO 2  emitted to the atmosphere whether originating from geothermal energy production or from other sources (such as e.g. conventional power plants). The standard approach to geologic carbon storage/sequestration is to inject CO 2  as a bulk phase into geologic formations at depth &gt;800 m. At this depth CO 2  is supercritical and buoyant with respect to the host rock fluids. As a result, buoyant CO 2  may migrate back to the shallow subsurface and surface (Ref. 6: Hawkins; Ref. 7: Benson). 
     Gislason et al. (Ref. 8) describes in a general way a method of capturing CO 2  that is transported in a 3 km pipeline to the pilot injection site as high pressurized gas. In the method envisaged, CO 2  is to be injected together with co-injected water, which will divert the injected CO 2  further down the well, which is according to the authors of the publication results in a single fluid phase entering the sequestration formation. Similarly Sigfusson et al. (Ref. 16) describes the injection of app. 175 t of CO 2  dissolved in 5000 t of water (at a depth of app 350 m below surface) into porous rocks located 400-800 m below the surface, and points to the fact that, even if large volumes of water are required for CO 2  storage via this method, the storage can be done at a lower distance from the surface than in case of supercritical CO 2 , because the CO 2  is dissolved and, hence, no longer buoyant. Likewise Gunnarson et al. (Ref 17) describes the continuous injection of CO 2  and H 2 S (dissolved in water at a depth of app 750 m below surface) into basaltic rock located about 2000 m below surface at temperatures ranging from 200 to 260 C, and points to the fact that the large depth and high temperature permits injection of larger quantities of CO 2  and H 2 S than what can be obtained with injection into more shallow and colder rock formations. 
     The methods described in detail in these publications differ from those of the present invention. Thus, neither of these publications points to the importance of the relationship between the downward velocity of the water flow and the capability to efficiently ensure that the CO 2  and/or H 2 S, released as bubbles of a given dimension at the merging point, are kept in solution at a given depth/pressure. The publications are, thus, silent as to the importance of transferring the water, which has been merged with the CO 2  and/or H 2 S rich gas streams, downwardly at a velocity, which is higher than the upward velocity of the bubbles of CO 2  and/or H 2 S gas dissolved in the water. In fact, quite to the contrary (Ref. 16) simply more generally points to the importance of dissolving the carbon-dioxide into the water during its injection, and mentions only typical volumetric flow rates and average residence times, just like it focuses on the importance of a fixed water to CO 2  mass ratio. This implies that it was apparently not fully understood by the authors of these publications at that point in time exactly which factors may in fact affect the usefulness of such methods. Similarly, neither of these publications points to the associated finding of the present invention that the water demand can thereby be diminished simply by increasing the downward flowing velocity of the water, e.g. by reducing the diameter of the pipe surrounding the merging point of the gas and water. This feature is of great economical importance to the feasibility of the methods of the present invention compared to those described in the prior art. 
     A review of the processes available for H 2 S abatement in the context of e.g. geothermal energy production (i.e. geothermal power plants) is provided by Sanopoulos and Karabelas (Ref. 9). Most known methods involve oxidation of H 2 S to elemental sulfur or sulfuric acid. The value of these products is low as there is either too little demand or excess supply. Disposal of these products is costly and can create environmental problems. 
     It has been speculated by Hibara et al. (Ref. 10) that H 2 S may be compressed and mixed with brine and reinjected into an auxiliary well. However, until now neither has such a method of abating hydrogen sulfide been described in detail, nor is it fully understood which factors may in fact affect the usefulness of such a method. 
     From the above it may be appreciated that there is a need for new, cost-effective and environmentally friendly abatement methods for abating CO 2  and/or H 2 S, whether originating from geothermal energy production or from other sources (such as e.g. conventional power plants). The inventors of the present invention have found a new method to facilitate the safe and permanent geologic storage/sequestration of both CO 2  and H 2 S which enables that the water demand can be diminished considerably by increasing the downward flow velocity of the water, e.g. by simply reducing the diameter of the pipe surrounding a merging point of the CO 2  and/or H 2 S rich gas stream and the water. Thus, the safe long-term storage of CO 2  and/or H 2 S can be facilitated simply by controlling how much CO 2  and/or H 2 S gas is to be dissolved in the injected water at the given merging point and at a given downward velocity of the water. 
     SUMMARY OF THE INVENTION 
     As noted above, it would be advantageous to achieve an effective and environmentally friendly method for abating carbon dioxide emissions and/or hydrogen sulfide both of which are emitted from power plants, conventional as well as geothermal. In general, the present invention preferably seeks to mitigate, alleviate or eliminate one or more of the above mentioned disadvantages singly or in any combination. 
     To better address one or more of these concerns, in a first aspect of the invention a method is provided for storing carbon dioxide (CO 2 ) and/or hydrogen sulfide (H2S) in a geological reservoir, comprising:
         pumping (or otherwise transferring) water from a water source to an injection well,   dissolving CO 2  and/or H 2 S gas in the water by merging a CO 2  and/or H 2 S rich gas stream with the water under conditions where the hydraulic pressure of the water is lower than the partial pressure of the CO 2  and/or H 2 S in the CO 2  and/or H 2 S rich gas stream,   ensuring that the dissolved CO 2  and/or H 2 S is kept in solution in the water by transferring the water comprising the dissolved CO 2  and/or H 2 S downwardly at a velocity, which is higher than the upward velocity of the bubbles of CO 2  and/or H 2 S gas in the water,   keeping the resulting pH value of said pressurized water stream containing said dissolved CO 2  and or H 2 S between about 2 and 4, preferably between about 2.5 and 3.5, more preferably about 3.2, and   injecting the water comprising the dissolved CO 2  and/or H 2 S into the geological reservoir.       

     In the context of the present invention the term pumping is to be understood as any means of transferring a liquid, e.g. water, from one location to another. 
     In the context of the present invention, the term water source or water is to be understood as any kind of water, such as e.g. groundwater, ocean/sea-water, spring water, geothermal condensate or brine, or surface waters from rivers, streams or lakes. 
     In the context of the present invention the term injection well is to be understood as any kind of structure providing for a possibility of placing fluids or gases either deep underground or just into the ground in a downwardly direction, such as e.g. a device that places fluid into reactive rock formations, such as basalt or basaltic rock, and porous rock formations, such as sandstone or limestone, or into or below the shallow soil layer. 
     In the context of the present invention, a CO 2  and/or H 2 S rich gas stream is to be understood as any gas stream of which the relative content of CO 2  and/or H 2 S is higher than the relative content of CO 2  and/or H 2 S of atmospheric air. 
     In the context of the present invention the term hydraulic pressure is to be understood as the pressure of a hydraulic fluid, which it exerts in all direction of a vessel, well, hose or anything in which it is present. A hydraulic pressure may give rise to flow in a hydraulic system as fluid flows from high pressure to low pressure. Pressure is measured in the SI unit pascal (Pa), i.e. one newton per square meter (1 N/m 2 ) or 1 kg/(m·s 2 ), or 1 J/m 3 . Other units of pressure commonly used are pound per square inch or, more accurately, pound-force per square inch (abbreviation: psi) and bar. In SI units, 1 psi is approximately equal to 6895 Pa and 1 bar is equal to 100,000 Pa. 
     In the context of the present invention, the term partial pressure or just pressure of a gas (of the CO 2  and/or H 2 S) is to be understood as the notional pressure of said given gas in a mixture of gases, if this given gas in itself occupied the entire volume of the original mixture at the same temperature. The total pressure of an ideal gas mixture is the sum of the partial pressures of the individual constituent gases in the mixture. 
     In the context of the present invention, the term velocity is to be understood as a vector quantity that refers to the rate at which an object changes its position in a certain direction. Thus, velocity equals distance/time and the SI unit is m/s. Water moving in a given direction at a given velocity will do so with a certain flow rate, which may be provided as either a volumetric flow rate or a mass flow rate. Volumetric flow rate is the volume of fluid, which passes a given point per unit time and is usually represented by the symbol Q (sometimes V). The SI unit for volumetric flow rate is m 3 /s. Thus, Volume flow rate equals Volume/time. Mass flow rate on the other hand is the mass of fluid, which passes a given point per unit time (kg/s). 
     In the context of the present invention injecting or inject is to be understood as introducing something forcefully into something else, i.e. to force a fluid into an underground structure. 
     In the context of the present invention, the term geological reservoir is to be understood as fractures in an underground structure, e.g. basaltic rock, that expands in other directions than upwardly and downwardly, which structure provides a flow path for the water injected into an injection well according to the present invention and may include what is referred to as a geothermal reservoir. In the present context the term geothermal reservoir is to be understood as fractures in hot rock that expand in other directions than upwardly and downwardly and provide a flowing path for the injected water from a well. 
     The fact that the method and the systems of the present invention ensures that the pressure of the dissolved CO 2  and/or H 2 S is less than the hydraulic pressure of the water (and is thereby kept in solution) when transferring the water downwardly, ensures that the CO 2  and/or H 2 S stays dissolved in the water, which improves considerably security due to decreased leakage risks. Also, this enables that the water demand of methods according to the present invention can be diminished considerably by increasing the downward flow velocity of the water, e.g. by simply reducing the diameter of the pipe surrounding a merging point of the CO 2  and/or H 2 S rich gas stream and the water. Injection of CO 2  promotes the carbonation of the host rock and thus facilitates the safe long-term storage of CO 2  in the subsurface. Accordingly, a method is provided where water-rock reactions already taking place in natural reactive rock, e.g. basaltic rock, reservoirs in geothermal systems are utilized by means of injecting CO 2  and/or H 2 S back into the reservoir geothermal system. The environmental impact caused by CO 2  and/or H 2 S gas emission from e.g. geothermal plants will therefore be lowered. Also, the safe long-term storage of CO 2  and/or H 2 S can be facilitated simply by controlling how much CO 2  and/or H 2 S gas is to be dissolved in the injected water at the given merging point and at the given downward velocity of the water. 
     Also, the abatement method of the present invention is very economical and environmentally friendly as there are no byproducts that need to be disposed of Returning the CO 2  and/or H 2 S back to where they came from has to be considered as an ideal method for reducing gas emission from e.g. geothermal power plants. 
     The fact that the method and the systems of the present invention ensures that the gas pressure (i.e. the partial pressure) of the dissolved CO 2  and/or H 2 S is less than the hydraulic pressure of the water (and is thereby kept in solution) when transferring the water downwardly, ensures that the gasses stays dissolved in the water and do not degas from the water. Thus, the method of the present invention minimizes the risk of gas bubbles rising out of the water, which would otherwise mean that the CO 2  and/or H 2 S would not be effectively transferred into the geological reservoir where the gasses are to absorbed and/or mineralized. 
     At the same time the low pH of the water promotes the dissolution of minerals in the geological reservoir thereby providing the cations necessary for carbon and sulphur mineralization and abatement. 
     Since the pressure of the CO 2  and/or H 2 S prior to injecting them into the water is larger than the hydraulic pressure of the water, gas bubbles will be present in the water at the merging point (i.e. the point of gas injection), but since the gas bubbles are transferred downwardly at a critical water velocity, it is ensured that the gas streams will dissolve into the water and stay dissolved, i.e. will stay in solution. 
     In one embodiment, said step of dissolving the gas in the water comprises conducting the CO 2  and/or H 2 S gas via an injection pipe having an open end extending down into said injection well at a depth that is selected such that the hydraulic pressure of the water in said injection well at said open end of the injection pipe is less than the CO 2  and/or H 2 S gas pressure in the injection pipe, while at the same time ensuring that the water is transferred downwardly at a velocity relative to the point where the gasses are injected into the injection well, which ensures that for a given subpart of the water stream the hydraulic pressure of the water is larger than the pressure of the dissolved CO 2  and/or H 2 S relatively shortly after the gasses have been injected into the water. Thus, the hydraulic pressure that is needed both to dissolve the CO 2  and/or H 2 S gas in the water and to keep the CO 2  and/or H 2 S gas in solution in the water is obtained by transferring the water and the gases to the appropriate depth(s) and therefore no external energy is needed at neither the merging point nor below to obtain or keep the hydraulic pressure needed. Furthermore, a method according to the present invention ensures that when the CO 2  and/or H 2 S is injected into the injection well (which is possible because the hydraulic pressure in the injection pipe is larger than the hydraulic pressure in the injection well) at the open end it will not start to “effervesce” after being injected, but instead be kept in a dissolved state, i.e. in solution, for the necessary time frame for the CO 2  and/or H 2 S mineralizing water rock reactions to take place. This is similar to avoiding the scenario that would otherwise occur when a bottle of soda is opened, and the bubbling of carbon dioxide starts and thus the releasing of the carbon dioxide from the bottle into the atmosphere. Thus, if the bottle is opened under a surrounding pressure equal to or higher than that in the bottle such a carbon dioxide bubbling would not occur. The low pH of the water, in a method according to a method according to the present invention, furthermore, due to the presence of dissolved CO 2  and/or H 2 S therein promotes the dissolution of minerals in the geological reservoir thereby providing the cations necessary for carbon and sulphur mineralization and abatement. 
     In one embodiment, the step of dissolving CO 2  and/or H 2 S gas in the water comprises conducting the CO 2  and/or H 2 S gas via an injection pipe having an open end extending down into said injection well where the injection pipe is surrounded by an outer pipe having an open end positioned at a larger depth than said open end of the injection pipe, said pumping of water being performed into the space between the outer pipe and the injection pipe, said depth at the open of the injection pipe within said outer pipe being selected such that the hydraulic pressure of the water within the outer pipe at said open end of the injection pipe is less than the CO 2  and/or H 2 S gas pressure in the injection pipe, while at the same time ensuring that the water is transferred downwardly at a velocity relative to the point where the gasses are injected into the injection well, which ensures that for a given subpart of the water stream the hydraulic pressure of the water is larger than the sum of the partial pressure of the dissolved CO 2  and/or H 2 S relatively shortly after the gasses have been injected into the water. 
     In one embodiment, the pumping rate of the water and the diameter of the pipe is selected such that the drag force of the downward flowing water into the injection well is larger than the buoyant force on the CO 2  and/or H 2 S. It is thus ensured that a constant downwardly flowing water stream is provided ensuring that the dissolved CO 2  and/or H 2 S will move downward and towards the storage reservoir. Methods or systems working with relatively small bubbles, e.g. below 6 mm in diameter, will according to the present invention need a minimum water velocity of between 0.4 m/s and 1.4 m/s depending on dynamic forces in the system. 
     In one embodiment, the pressure of the CO 2  gas at the open end of the injection pipe (i.e. where the hydraulic pressure of the water in said injection well is less than the CO 2  gas pressure in the injection pipe) is between 20-35 bar. At this pressure, the temperature of the water may be, but is not limited to, between 20-40° C. resulting in a single fluid phase entering the storage formation, which e.g. consists of relatively fresh basaltic lavas. 
     In one embodiment, the depth at said open end of the outer pipe is selected such that pH value of the injection water containing dissolved CO 2  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 CO 2  and/or H 2 S leave the outer pipe and the sequestration of the CO 2  and H 2 S in rocks starts, i.e. the storing of the carbon dioxide CO 2  and/or hydrogen sulphide H 2 S in the geological reservoir. The lower the pH value the faster will the dissolution rate be of the rock meaning that with such a low pH value the sequestration of the carbon dioxide CO 2  and/or hydrogen sulphide H 2 S in the storage reservoir will be significantly enhanced. 
     In one embodiment, said step of dissolving the CO 2  and/or H 2 S gas in said water further includes mixing, e.g. by means of a sparger and/or mixer, the dissolved CO 2  and/or H 2 S with the water at or below the merging point so as to obtain a uniform mixing of the CO 2  and/or H 2 S gas in the water, breaking up larger bubbles and dissolving any remaining CO 2  and/or H 2 S gas bubbles in the water. Accordingly, more turbulence will be created in the mix of CO 2  and/or H 2 S gas and the pressurized water, which will enhance the dissolution of CO 2  and/or H 2 S gas at and/or below the merging point further. Also, large CO 2  and/or H 2 S gas bubbles will be split into smaller gas bubbles which will also enhance the dissolution of the CO 2  and/or H 2 S. 
     In one embodiment, said source of water is selected from one or more of the following: surface waters, groundwater or seawater. 
     In one embodiment, said step of dissolving the CO 2  gas with said water further includes maximizing the interfacial area between the CO 2  and/or H 2 S gas and the water. Accordingly, the CO 2  and/or H 2 S gas bubbles will be equally distributed within the pressurized water and further the average diameter of the bubbles will be reduced causing said maximization of the interfacial area between the CO 2  and/or H 2 S gas and the water, where both these factors enhance the dissolution rate of CO 2  and/or H 2 S in the pressurized water significantly. 
     In one embodiment, said step of dissolving the CO 2  and/or H 2 S gas in said water further includes mixing the dissolved CO 2  and/or H 2 S with the water so as to obtain a uniform mixing of the CO 2  and/or H 2 S gas in the water and dissolving any remaining CO 2  and/or H 2 S gas bubbles in the water. Accordingly, more turbulence will be created in the mix of CO 2  and/or H 2 S gas and the pressurized water, which will enhance the dissolution of CO 2  and/or H 2 S gas further. Also, large CO 2  and/or H 2 S gas bubbles will be split into smaller gas bubbles which will also enhance the dissolution rate of the CO 2  and/or H 2 S. 
     In one embodiment, said step of dissolving CO 2  and/or H 2 S gas in the water comprises conducting the CO 2  and/or H 2 S gas via an injection pipe having an open end extending down into said injection well at a depth that is selected such that the hydraulic pressure of the water in said injection well at said open end of the injection pipe is less than the CO 2  and/or H 2 S gas pressure in the injection pipe, while at the same time ensuring that the water is transferred downwardly at a velocity relative to the point where the gasses are injected into the injection well, which ensures that for a given subpart of the water stream the hydraulic pressure of the water is larger than the partial pressure of the dissolved CO 2  and/or H 2 S relatively shortly after the gasses have been injected into the water. The hydraulic pressure is slightly less than the gas pressure at the depth of the merging point, firstly to ensure that the CO 2  and/or H 2 S gas can enter the water in the injection well at the depth of the merging point and secondly, that, after having been dissolved in the water and moved downwardly at a given downwardly velocity, the hydraulic pressure of the water at that somewhat larger depth is larger than the pressure of the CO 2  and/or H 2 S. Accordingly, by selecting the depth of the merging point in the injection well and the downwardly velocity of the water it is ensured that the CO 2  and/or H 2 S gas bubbles coming from the open end of the injection pipe will within very short timeframe be dissolved in the water and the CO 2  and/or H 2 S will stay dissolved in the water prior to the mineralization process within the geological reservoir. At the same time the low pH of the water, due to the addition of the CO 2  and/or H 2 S gas promotes the dissolution of minerals in the geological reservoir thereby providing the cations necessary for carbon and sulphur mineralization and abatement. 
     In one embodiment, the method further comprises the step of estimating the mineralization capacity of the CO 2  and/or H 2 S where the step of estimating this comprises:
         dissolving, in addition to said CO 2  and/or H 2 S, a tracer substance in the water, the concentration of the dissolved CO 2  and/or H 2 S and the dissolved tracer substance being performed in a controllable way such that the initial molar ratio between CO 2  and/or H 2 S and the tracer substance is pre-determined,   monitoring, in response to injecting said CO 2  and/or H 2 S and the dissolved tracer substance, the molar ratio between the CO 2  and/or H 2 S and the tracer substance in a monitoring well, the monitoring well being a well interlinked to said injection well via a flow path such that at least a part of said injected water mixed with said dissolved CO 2  and/or H 2 S and said tracer substance flows to said monitoring well via said flow path, the monitoring including measuring the concentration of the CO 2  and/or H 2 S and the tracer substance and based thereon the molar ratio between the CO 2  and/or H 2 S and the tracer substance at said monitoring well, and   determining an abatement indicator indicating the amount of CO 2  and/or H 2 S abatement achieved via water-rock reactions, said determination being based on comparing the molar ratio between the CO 2  and/or H 2 S and the tracer substance in the monitoring well with the corresponding molar ratio in the injection well at the merging point.       

     Based on such a measurement it is possible to determine whether the geological reservoir in question possesses the ability to store in mineralogical form the CO 2  and/or H 2 S, which is injected via the injection well. 
     As regards CO 2  said tracer substance can be, but is not limited to, SF5CF3 tracer, SF 6  or Rhodamine tracer (all being conservative tracers), or C-14 tracer to trace only the carbon. One or more of these tracers may be used at the same time. 
     Similarly it is possible to determine whether geological systems in e.g. Iceland, possesses the ability to mineralize H 2 S through water-rock reactions by use of tracer substance such as, but not limited to, iodine ions by dissolving KI in the pressurized water. 
     In one embodiment, the method further comprises carrying out a correction of said abatement indicator taking into account oxidation of H 2 S with other sulfide species. This will thus make the estimation of the abatement capacity more precise. Correction may be made by analyzing other types of sulfur in the geothermal water from the injection well, compare them to values obtained prior to injection of the H 2 S and adding the excess sulfur species (e.g. SO 4   2−  and S 2 O 3   − ) formed by oxidation of H 2 S to the H 2 S value before calculating the H 2 S abatement index. 
     In one embodiment, the interlink between said injection well and monitoring well is a fracture in the geological reservoir. 
     In one embodiment, said method further comprises providing a constriction at the open end of said injection pipe so as to maintain high hydraulic pressure in the injection pipe so as to further secure that the CO 2  or the H 2 S gas will remain dissolved in the injected water. 
     In a second aspect of the invention a system is provided adapted for abating CO 2  and/or H 2 S, comprising:
         means for pumping water from a water source into an injection well,   means for pumping CO 2  and/or H 2 S gas into an injection well   means for dissolving the CO 2  and/or H 2 S gas in the water at a depth, h1≥0, in the injection well where the hydraulic pressure of the water is lower than the pressure of the CO 2  and/or H 2 S,   means for transferring said water stream from said depth h1≥0 to a greater depth h1+h2, where h1+h2&gt;h1, at a downward flow velocity, which is higher than the upward flow velocity of the bubbles of said CO 2  and/or H 2 S gas, resulting from the buoyant force on said bubbles of CO 2  and/or H 2 S gas in said water,   means for keeping the resulting pH value of said pressurized water stream containing said dissolved CO 2  and or H 2 S between about 2 and 4, preferably between about 2.5 and 3.5, more preferably about 3.2, and   means for injecting the water comprising said dissolved CO 2  and/or H 2 S into a geological reservoir.       

     In one embodiment, said means for dissolving CO 2  and/or H 2 S gas in the water comprises an injection pipe for conducting high pressurized CO 2  and/or H 2 S gas into the injection well, the injection pipe having an open end extending down into said injection well at a depth h1≥0 that is selected such that the hydraulic pressure of the water in said injection well at said open end of the injection pipe is less than the CO 2  and/or H 2 S gas pressure in the injection pipe, and pump means enabling a downward flow velocity of the water higher than the upward flow velocity of bubbles of said CO 2  and/or H 2 S gas at depths larger than h1, thereby ensuring that the water is transferred to depths larger than h1 without the CO 2  and/or H 2 S escaping the water. 
     In one embodiment, the system further comprises an outer pipe surrounding said injection pipe having an open end extending down into said injection well at a further depth h1+h2, said means for pumping being a water pump that pumps the water into the space between the outer pipe and the injection pipe, said means for injecting the dissolved CO 2  and/or H 2 S into the geological reservoir being the downward flow velocity and resulting flow rate of water formed through the pumping of the water into said space between the outer pipe and the injection pipe. In a situation wherein the gas is restricted to CO 2  the h1+h2 may be selected such that the pH value of the injection water containing dissolved CO 2  is below a pre-defined pH limit. 
     In one embodiment, said means for dissolving CO 2  and/or H 2 S with the water further comprises:
         a sparger mounted at said open end of the gas injection pipe adapted to maximize the interfacial area between the CO 2  and/or H 2 S gas and the water, or   a mixer mounted within said outer pipe between said open end of the injection pipe and said open end of the outer pipe adapted for mixing the CO 2  and/or H 2 S with the water so as to obtain a uniform mixing of the CO 2  and/or H 2 S gas in the water and dissolving any remaining bubbles of CO 2  and/or H 2 S gas in the water, or   a sparger mounted at said open end of the injection pipe adapted to maximize the interfacial area between the CO 2  and/or H 2 S gas and the water and a mixer mounted within said outer pipe between said sparger and said open end of the outer pipe adapted for mixing the CO 2  and/or H 2 S with the water so as to obtain a uniform mixing of the CO 2  and/or H 2 S gas in the water and dissolving any remaining bubbles of CO 2  and/or H 2 S in the water.       

     Accordingly, a practical and cost-effective system for in situ mineral carbonation in reactive rocks, e.g. basaltic rocks, is provided that injects water with high enough concentrations of dissolved CO 2  and/or H 2 S concentration to favor reaction with the reactive rock, e.g. basaltic rock. Similarly, the low pH of the water promotes the dissolution of minerals in the geological reservoir thereby providing the cations necessary for carbon and sulphur mineralization and abatement. 
     In a method according to the present invention, once dissolved, CO 2  and/or H 2 S is no longer buoyant, which dramatically improves security due to decreased leakage risks. Injection of dissolved CO 2  and/or H 2 S also promotes the carbonation of the host rock and thus facilitates the safe long-term storage of CO 2  and/or H 2 S in the subsurface. 
     It should be noted that the term water can according to the present invention mean fresh water, water from geothermal wells, brine, sea water and the like. Said water source may, thus, be any type of water. Likewise, the CO 2  and/or H 2 S gas may originate from any source, such as conventional power plants, geothermal power plants, industrial production, gas separation stations or the like. 
     In general, the various aspects of the invention may be combined and coupled in any way possible within the scope of the invention. These and other aspects, features and/or advantages of the invention will be apparent from and elucidated with reference to the embodiments described hereinafter. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Hereinafter a number of embodiments of the invention are described, by way of example only, with reference to the drawings, in which 
         FIG. 1  shows a flowchart of a method according to the present invention of abating CO 2  and/or H 2 S in a geological reservoir. 
         FIG. 2  shows a schematic representation of host rock and formation fluid interaction during in situ CO 2  mineral sequestration. 
         FIG. 3  shows a flowchart of an embodiment of a method according to the present invention indicating in more details how the dissolved CO 2  and/or H 2 S is injected into the geological reservoir. 
         FIG. 4  shows a system according to the present invention for storing carbon dioxide (CO 2 ) in a geological reservoir. 
         FIG. 5  shows a flowchart of an embodiment of a method according to the present invention of abating hydrogen sulfide (H 2 S) in a geological reservoir. 
         FIG. 6  depicts schematically a method in accordance with the present invention showing an injection well where water is continuously being pumped into the well. 
         FIG. 7  shows the relation between the downward flow velocity (m/s) of water into an injection well and the diameter of spherical (upper line) and elongated (lower line) gas bubbles where the buoyancy and downward drag force are in a balance at a given temperature, pressure and gas and water compositions. The shaded area represents bubbles with a form between spherical and elongated. As is clear from this figure, means capable of creating small bubbles will result in a method or system according to the present invention (i.e. being at least in balance) being capable of operation at relatively low flow velocities, e.g. below 0.4 m/s, whereas means limited to larger bubbles will necessitate a means capable of providing higher flow velocities, e.g. above 0.8 m/s, in order to be able to provide a method or system according to the present invention (i.e. being in balance). 
         FIG. 8  shows an expanded view of the first quarter of  FIG. 7 . 
         FIGS. 9-11  depicts graphically different embodiments of a system according to the present invention for abating hydrogen sulfide (H 2 S) and carbon dioxide (CO 2 ), in a geological reservoir. 
     
    
    
     DESCRIPTION OF EMBODIMENTS 
       FIG. 1  shows a flowchart of a method according to the present invention of abating CO 2  and/or H 2 S in a geological reservoir. The term geological reservoir may be understood as fractures in hot rock that expand in other directions than upwardly and downwardly and provide a flowing path for the injected water from the well. 
     In a first step (S 1 )  101 , water is pumped from water source to an injection well. The water source may be, but is not limited to, geothermal water, brine and the like, or it can be fresh water and sea water. For simplicity, hereafter the term “water” will be used. Also, the temperature of the water can vary from being only a few degrees Celsius up to several hundred degrees. 
     In a second step (S 2 )  103 , CO 2  and/or H 2 S gas is merged with the water at a merging point where the hydraulic pressure of the water is lower than the pressure of CO 2  and/or H 2 S, while at the same time ensuring that the water is transferred downwardly at a velocity relative to the point where the gasses are injected into the injection well, which ensures that for a given subpart of the water stream the hydraulic pressure of the water is larger than the partial pressure of the CO 2  and/or H 2 S relatively shortly after the gasses have been injected into the water. 
     In step (S 3 )  105 , the water with the dissolved CO 2  and/or H 2 S is injected into the geological reservoir. 
     In one embodiment, step (S 2 )  103  comprises conducting the CO 2  and/or H 2 S gas via an injection pipe having an open end extending down into said injection well at a depth, h1≥0, that is selected such that the hydraulic pressure of the water in the injection well at the open end of the injection pipe is less than the CO 2  and/or H 2 S gas pressure in the injection pipe. This is simply to enable the CO 2  and/or H 2 S gas to flow into the water at the depth h1≥0. At the same time a downward flow velocity of the water higher than the upward flow velocity of the bubbles of said CO 2  and/or H 2 S gas at depths larger than h1 is provided, thereby ensuring that the water is transferred to depths larger than h1 without the CO 2  and/or H 2 S escaping the water. 
     In a preferred embodiment the pressure of the CO 2  gas at the open end of the injection pipe is between 20-35 bar. This large pressure ensures that the pH value of water containing the dissolved CO 2  is relatively low which will enhance the CO 2  water rock reactions in the geological reservoir. 
     One of the important aspects of the present invention is the dissolution of CO 2  (and/or H 2 S) in water before it is dispersed as a single-phase fluid into the pore space of reactive rock formations. The CO 2  dissolves to form carbonic acid (H 2 CO 3 ), which can dissociate into bicarbonate (HCO 3 ) and carbonate (CO 3   2- ) according to: 
       CO 2(g) ═CO 2(aq)   (1a)
 
       CO 2(aq) +H 2 O═H 2 CO 3(aq)   (1b)
 
       H 2 CO 3 (aq) =HCO 3   − +H +   (1c)
 
       HCO 3   − =CO 3   2− +H +   (1d)
 
     For example, plagioclase ((Ca, Na)Al 1.70 Si 2.30 O 8 ), olivine ((Mg, Fe) 2 SiO 4 ) and pyroxene ((Ca, Mg, Fe) 2 SiO 3 ) are the most abundant primary minerals in basaltic rocks but basaltic glasses are also common. When the minerals and glasses come in contact with the injected acidic fluid, dissolution reactions occur leaching cations such as Ca 2+ , Mg 2+  and Fe 2+  from the rock matrix. Reactions 2-5 here below show the dissolution of plagioclase, olivine, pyroxene, and basaltic glass, respectively. Composition of basaltic glass in reaction 5 is that of Stapafell glass as reported in the scientific literature by Oelkers and Gislason (Ref. 11). 
       (Ca,Na)Al 1.70 Si 2.30 O 8(s) +6.8H + ═(Ca 2+ ,Na + )+1.70Al 3+ +2.3SiO 2(aq) +3.4H 2 O (l)   (2)
 
       (Mg,Fe) 2 SiO 4(s) +4H + =2(Mg,Fe) 2+ +SiO 2(aq) +2H 2 O (l)   (3)
 
       (Ca,Mg,Fe) 2 SiO 3 +2H + =2(Ca,Mg,Fe) 2+ +SiO 2(aq) +H 2 O (l)   (4)
 
       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(aq) +0.36Al 3+ +0.19Fe 2+ +0.28Mg 2+ +0.26Ca 2+ +0.08Na + +0.008K 2+ +1.30H 2 O (l)   (5)
 
     As dissolution reactions 2-5 proceed in the subsurface after CO 2  and/or H 2 S injection, protons (H + ) are consumed and pH of formation fluids increases. 
     Concentration of leached cations also builds up as the water flows away from the injection well, as displayed in  FIG. 2 , showing a schematic representation of host rock and formation fluid interaction during in situ CO 2  mineral sequestration after CO 2  is injected into an injection well  2000 . The left side in  FIG. 2  shows a depth scale extending below 800 m. The arrows  2005 - 2007  indicate the direction of regional groundwater flow and also 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 formations and leaches cations out of the rock matrix. At more distance from the injection well  2006  the concentration of the ions increases as dissolution of rock proceeds and the pH of water increases. At further distance from the injection well  2007  mineral supersaturation and precipitation occurs where clays and zeolites compete with carbonates for dissolved cations. 
     At certain concentrations, the water becomes supersaturated with respect to secondary minerals like carbonates, which begin to precipitate according to reaction 6: 
       (Ca,Mg,Fe) 2+ +CO 3   2− ═(Ca,Mg,Fe)CO 3(s)   (6)
 
     Calcite (CaCO 3 ), dolomite (CaMg(CO 3 ) 2 ), magnesite (MgCO 3 ) and siderite (FeCO 3 ) are among proposed carbonate forming minerals. It is difficult to predict beforehand which of these carbonates will actually precipitate in the subsurface during CO 2  injection as well as to what extent they will form. Other minerals, such as clays, hydroxides and zeolites, are likely to form as well and compete with reaction 6 for leached cations. 
       FIG. 3  shows a flowchart of an embodiment of a method according to the present invention indicating in more details how said step (S 3 )  105  is performed. 
     In step (S 3 ′)  201 , the hydraulic pressure of the water pumped from said water source is increased so as to form pressurized water. This may e.g. be done by pumping the water from the water source to the injection well via a pipeline, where the pressure in the pipeline is increased e.g. via the appropriate equipment such as a water pump such that the pressure can be controlled and adjusted to the pressure of the CO 2  and/or H 2 S gas to be dissolved. 
     In step (S 3 ″)  203 , the CO 2  and/or H 2 S gas is dissolved with the pressurized water, where the hydraulic pressure of the water is selected such that during the gas dissolution the hydraulic pressure of the water is less than the pressure of the CO 2  and/or H 2 S gas. The pressure of the water is in one embodiment around 6 bars or somewhat lower than the pressure of the CO 2  and/or H 2 S gas. In this embodiment, said step (S 3 )  105  of injecting the dissolved H 2 S into the geological reservoir is performed via an injection pipe having an open end extending down into the injection well at a depth, h1≥0, that is below the surface level of the water in the injection well. This depth is preferably selected such that the hydraulic pressure of the water in the injection well 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 at a somewhat larger depth, h2, reached when the water flows downward, is larger than the pressure of the dissolved CO 2  and/or H 2 S. The reason of doing so is to ensure that when the water with the dissolved CO 2  and/or H 2 S comes out from the open end of the injection pipe, the surrounding pressure will be larger than the pressure of the dissolved CO 2  and/or H 2 S. By doing so the dissolved CO 2  and/or H 2 S will stay in a dissolved state until the CO 2  and/or H 2 S mineralizing water rock reactions start. At the same time the low pH of the water containing the dissolved CO 2  and/or H 2 S promotes the dissolution of minerals in the geological reservoir thereby providing the cations necessary for carbon and sulphur mineralization and abatement. This gas dissolving process can be facilitated by using the appropriate equipment for maximizing the interfacial area between the H 2 S gas and the water and/or mixing the dissolved H 2 S with the water so as to obtain a uniform mixing of the H 2 S in the water and dissolving any remaining H 2 S gas bubbles in the water. 
     In one embodiment, said step (S 3 )  105  of dissolving CO 2  and/or H 2 S gas in the water comprises conducting the CO 2  and/or H 2 S gas via an injection pipe having an open end extending down into said injection well at a depth, h1≥0, that is selected such that the hydraulic pressure of the water in the injection well at the open end of the injection pipe is less than the CO 2  and/or H 2 S gas pressure in the injection pipe. Preferably, the hydraulic pressure is slightly less that the CO 2  and/or H 2 S gas pressure in the pipeline at this open end, firstly to ensure that the CO 2  and/or H 2 S gas can enter the water in the injection well, and secondly, that after having entered the water at depth h1≥0 and having travelled some distance downwardly with the water stream, that the hydraulic pressure at that larger depth, h1+h2 (i.e. after the CO 2  and/or H 2 S has travelled the distance h2 downwardly), is larger than the pressure of the dissolved CO 2  and/or H 2 S in the water. This injection pipe may e.g. be a pipe that extends from a gas separation station where CO 2  and/or H 2 S gas is separated from geothermal gas and subsequently conducted to the injection well via a pipeline. 
       FIG. 4  depicts graphically an embodiment of a system  200  according to the present invention for storing carbon dioxide CO 2  in a geological reservoir  201 . The system comprises a CO 2  gas pipeline  202 , a wellhead  209 , water inlet  203 , a gas injection pipe  206 , a sparger  207 , a mixer  208  and an outer water injection pipe  204 . The CO 2  is conducted to the wellhead  209  under high pressure and into the injection well  210  via the gas injection pipe  206  having an open end at a depth h1≥0, but the injection pipe  206  is surrounded by an outer water injection pipe  204  having an open end positioned at depth h1+h2. In this embodiment, the amount of water (liters/second) pumped into the injection well  210  is controlled via a valve  211 , where the water is pumped into the space between the injection pipe  206  and the outer water pipe  205 . 
     The depth at the open of the injection pipe at depth h1≥0 is selected such that the hydraulic pressure of the water at this depth is slightly less than the CO 2  gas pressure in the injection pipe. This is to ensure that the CO 2  gas can go into the water. Further downwards of the injection of the CO 2  gas into the water, i.e. at depth h1+Δh with Δh«h1 the hydraulic pressure of the water is larger than the pressure of the dissolved CO 2 . This is to ensure that the pressure of the dissolved CO 2  will be less than the hydraulic pressure so that it stays dissolved in the water. 
     The water flow velocity into the space between the injection pipe  206  and the outer pipe  204  is selected such that the flow velocity of the water as indicated by the arrows is larger than the upwardly velocity of the CO 2  gas bubbles due to the buoyant force on the CO 2  gas at the open end of the injection pipe. Hence, as CO 2  bubbles move downward, the hydraulic pressure increases, CO 2  dissolves into the water and bubbles become smaller resulting in reduced upward velocity of the bubbles. A preferred condition is when the bubbles are small since then the upward travelling velocity of the bubbles is small and also the total surface area is larger resulting in enhanced dissolution rate. 
     One way to analyze the water flow velocity needed down the pipe to avoid spherical gas bubbles from rising up the injection pipe is to calculate when the buoyancy of the gas bubbles, with the density of the carbon dioxide bubbles, at the relevant pressure and temperature (in the form of perfect sphere) is equal to the drag force at the downward flow velocity of the water. At these conditions the spherical gas bubbles would be stationary. If the flow velocity would be less the bubbles would travel upwards and if the flow velocity would be higher the bubbles would travel downwards with the water flow. The results of the calculations are shown in  FIGS. 7 and 8 . The horizontal axis shows the downward flow velocity of the water in m/s and the vertical axis shows the diameter of the bubble in mm. As the gas bubbles are not solid spheres they can deform and will become oblate spheroids in a flowing medium. This applies especially for the larger gas bubbles as the surface tension will keep the smaller ones more spherical. Methods or systems working with relatively small bubbles, e.g. below 6 mm in diameter, will according to the present invention be capable of operation at relatively low flow velocities, e.g. below 0.4 m/s, whereas methods or systems working with relatively large bubbles, e.g. above 20 mm in diameter, will according to the present invention be capable of operation at relatively high flow velocities, e.g. above 0.8 m/s. 
     Referring back to  FIG. 4 , the sparger  207  is placed at the open end of the injection pipe  206  for maximizing the interfacial area between the CO 2  gas and the water. By doing so, the CO 2  gas bubbles will be equally distributed within the water, and further, the average diameter of the bubbles will be reduced causing said maximization of the interfacial area between the CO 2  gas and the water. 
     Below the sparger is the mixer  208 , the role of which is to mix the dissolved CO 2  with the water so as to obtain a uniform mixing and dissolve any remaining CO 2  gas bubbles in the water. Accordingly, more turbulence will be created, which will enhance the dissolution of CO 2  gas further. Also, large CO 2  gas bubbles will be split into smaller gas bubbles, which will also enhance the dissolution rate of the CO 2 . 
     In one embodiment, the depth h1 of the water column within the outer pipe is around 250 m meaning that the hydraulic pressure becomes 24.5 bars. This means that the pressure of the CO 2  gas is slightly larger than 24.5 bars. As soon as it leaves the open end of the injection pipe  206  and passes the sparger  207  it will be dispersed as small bubbles and thereafter dissolved in the water. Due to the constant water flow into the space between the injection pipe and the outer pipe  204  a vertical downwardly pointing velocity is created causing the dissolved CO 2  to travel towards the open end of the injection pipe at said depth of h1+h2. This depth is preferably selected such that the pH value of the dissolved CO 2  will be around 3.2, but the pH value decreases with increasing CO 2  pressure. This corresponds when h1+h2≈520 m. It is at this depth that the dissolved CO 2  leaves the system  200  and the sequestration of the CO 2  in basaltic rocks starts. The lower the pH value is, the higher will the dissolution rate be within the basaltic rock. 
     An additional advantage of the present invention is its cost relative to conventional technologies. The overall “on site cost” of this gas mixture capture, transport and storage at the CarbFix2 Hellisheiði site is US $24.8/ton of gas mixture CO 2 /H 2 S. This is significantly lower than the price (USD 35 to USD 143 pr. ton CO 2 ) that has been reported by others (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 has demonstrated the efficiency and cost advantages of the capture and storage of mixed, dissolved gas streams at the deep geological sites. 
     While the present invention has been illustrated and described in detail in the drawings and foregoing description, such illustration and description are to be considered illustrative or exemplary and not restrictive; 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. 
     Referring to the accompanying figures the present invention in particular relates to a method of abating carbon dioxide (CO 2 ) and/or hydrogen sulfide (H 2 S), comprising the steps of:
         pumping or transferring water from a water source into an outer pipe ( 205 ) of an injection well ( 210 ) thereby creating a pressurized water stream in said outer pipe ( 205 ),   pumping a CO 2  and/or H 2 S rich gas into a gas injection pipe ( 206 ) of an injection well ( 210 ) thereby creating a CO 2  and/or H 2 S rich gas stream comprising pressurized CO 2 , and/or pressurized H 2 , in said injection pipe ( 206 )   dissolving substantially all of said pressurized CO 2  and/or H 2 S gas of said CO 2  and/or H 2 S rich gas stream in said pressurized water stream by merging said pressurized water stream and said CO 2  and/or H 2 S rich gas stream at a depth, h1≥0, where the hydraulic pressure of said water in said outer pipe ( 205 ), p(W), is lower than the pressure of said CO 2  and/or H 2 S, p(C) and/or p(H), in said injection pipe ( 206 )   keeping said dissolved CO 2  and/or H 2 S in solution in said water stream by transferring said water stream from said depth h1≥0 to a depth h1+h2, where (h1+h2)&gt;h1, at a downward flow velocity, v(W), which at h1+h2 is higher than the upward flow velocity of said CO 2  and/or H 2 S gas, v(C) and/or v(H), resulting from the buoyant force on bubbles of CO 2  and/or H 2 S gas in said water stream at said depth h1+h2   injecting said pressurized water stream comprising dissolved CO 2  and/or H 2 S into a geological reservoir comprising reactive rocks at h1+h2 or at a depth&gt;(h1+h2).       

     In a particular preferred embodiment of a method according to the invention the geological reservoir is a geothermal reservoir. 
     In a particular preferred embodiment of a method according to the invention the interfacial area between the CO 2  and/or H 2 S to be dissolved in said water stream is increased by fitting said injection pipe ( 206 ) with a means for sparging ( 207 ) at the merging point at depth h1. 
     In a further particularly preferred embodiment of a 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. 
     In a further particularly preferred embodiment of a 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, e.g. 0.65-0.85 m/s, such as e.g. 0.7 m/s. 
     In a further particularly preferred embodiment of a method according to the invention said injection pipe ( 206 ) extends downwardly inside said outer pipe ( 205 ), comprising said pressurized water stream, and has an open end at said depth h1≥0. 
     In a yet further particularly preferred embodiment of a method according to the invention said outer pipe ( 205 ), comprising said pressurized water stream, has an open end at said depth h1+h2. 
     In a yet further particularly preferred embodiment of a method according to the invention the pressure of CO 2 , p(C O 2 ), at the merging point at depth h1≥0 is between about 15-40 bar, such as 17-38 bar, e.g. 20-36 bar, preferably between about 22-34 bar, more preferably between about 24-32 bar, most preferably about 24.5 bar. 
     In a yet further particularly preferred embodiment of a method according to the invention the pressure of H 2 S, (pH), at the merging point at depth h1≥0 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, e.g. 5.7 and 6.3 bar and most preferably about 6 bar. 
     In a yet further particularly preferred embodiment of a method according to the invention the resulting pH value of said pressurized water stream containing said dissolved CO 2  and or H 2 S is between about 1 and 5, such as between about 2 and 4, preferably between about 2.5 and 3.5, such as between about 2.6 and 3.4, more preferably about between 2.7 and 3.3, such as 3.2. 
     In a yet further particularly preferred embodiment of a method according to the invention, the method further comprises the steps of: 
     dissolving a tracer substance, in a predetermined molar ratio compared to said dissolved CO 2  and/or H 2 S, in said pressurized water stream at said depth h1≥0 in said outer pipe ( 205 ) in said injection well ( 210 / 612 ), 
     establishing a monitoring well ( 610 ) being interlinked to said outer pipe ( 205 ) of said injection well ( 210 / 612 ) via a flow path ( 614 ), whereby at least a part of said pressurized water mixed with said dissolved CO 2  and/or H 2 S and said tracer substance flows from said outer pipe ( 205 ) of said injection well ( 210 / 612 ) to said monitoring well ( 610 ) via said flow path ( 614 ), 
     measuring the concentration of CO 2  and/or H 2 S and tracer substance at said monitoring well ( 610 ) and establishing based thereon the molar ratio between CO 2  and/or H 2 S and tracer substance at said monitoring well ( 610 ), and 
     determining an abatement indicator indicating the degree of CO 2  and/or H 2 S abatement based on comparing the molar ratio between CO 2  and/or H 2 S and the tracer substance at said monitoring well ( 610 ) with said predetermined molar ratio in said pressurized water stream at said depth h1 in said outer pipe ( 205 ) in said injection well ( 210 / 612 ). 
     Referring to the accompanying figures the present invention furthermore in particular relates to a system for abating carbon dioxide (CO 2 ) and/or hydrogen sulfide (H 2 S), comprising: 
     an injection well ( 210 ) 
     an outer pipe ( 205 ) extending downwardly inside said injection well ( 210 ) 
     an injection pipe ( 206 ) extending downwardly inside said injection well ( 210 ) means for pumping or transferring water from a water source into said outer pipe ( 205 ) thereby creating a pressurized water stream in said outer pipe ( 205 ), 
     means for pumping a CO 2  and/or H 2 S rich gas into said injection pipe ( 206 ) thereby creating a CO 2  and/or H 2 S rich gas stream comprising pressurized CO 2 , and/or pressurized H 2 , in said injection pipe ( 206 ) 
     means for merging said pressurized water stream and said CO 2  and/or H 2 S rich gas stream at a depth, h1≥0, where the hydraulic pressure of said water in said outer pipe ( 205 ), p(W), is lower than the pressure of said CO 2  and/or H 2 S, p(C) and/or p(H), in said injection pipe ( 206 ) 
     means for transferring said water stream from said depth h1≥0 to a depth h1+h2, where (h1+h2)&gt;h1, at a downward flow velocity, v(W), which at h1+h2 is higher than the upward flow velocity of said CO 2  and/or H 2 S gas, v(C) and/or v(H), resulting from the buoyant force on bubbles of CO 2  and/or H 2 S gas in said water stream at said depth h1+h2 
     means for keeping the resulting pH value of said pressurized water stream containing said dissolved CO 2  and or H 2 S between about 2 and 4, preferably between about 2.5 and 3.5, more preferably about 3.2 
     means for injecting said pressurized water stream comprising dissolved CO 2  and/or H 2 S into a geological reservoir comprising reactive rocks at h1+h2 or at a depth&gt;(h1+h2). 
     In a particular preferred embodiment of a system according to the present invention the system further comprises means for sparging ( 207 ) fitted onto said injection pipe ( 206 ) at the merging point at depth h1≥0. 
     In a further particularly preferred embodiment of a 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. 
     In a further particularly preferred embodiment of a system according to the invention said means for transferring said water stream from said depth h1 to a depth h1+h2, where (h1+h2)&gt;h1, is capable of providing a downward flow velocity of said water, v(W), which is 0.5-1 m/s, such as 0.6-0.9 m/s, e.g. 0.65-0.85 m/s, such as e.g. 0.7 m/s. 
     In a further particularly preferred embodiment of a system according to the present invention said injection pipe ( 206 ) extends down into said outer pipe ( 205 ) and has an open end at said depth h1≥0. 
     In a yet further particularly preferred embodiment of a system according to the present invention said outer pipe ( 205 ) has an open end at said depth h1+h2. 
     In a yet further particularly preferred embodiment of a system according to the present invention, the system further comprises: 
     means for dissolving a tracer substance, in a predetermined molar ratio compared to said dissolved CO 2  and/or H 2 S, in said pressurized water stream at said depth h1≥0 in said outer pipe ( 205 ) in said injection well ( 210 / 612 ), 
     a monitoring well ( 610 ) 
     a flow path ( 614 ), whereby at least a part of said pressurized water mixed with said dissolved CO 2  and/or H 2 S and said tracer substance flows from said outer pipe ( 205 ) of said injection well ( 210 / 612 ) to said monitoring well ( 610 ), 
     means for measuring the concentration of CO 2  and/or H 2 S and tracer substance at said monitoring well ( 610 ) and establishing based thereon the molar ratio between CO 2  and/or H 2 S and tracer substance at said monitoring well ( 610 ), and 
     means for determining an abatement indicator indicating the degree of CO 2  and/or H 2 S abatement based on comparing the molar ratio between CO 2  and/or H 2 S and the tracer substance at said monitoring well ( 610 ) with said predetermined molar ratio in said pressurized water stream at said depth h1 in said outer pipe ( 205 ) in said injection well ( 210 / 612 ). 
     The methods and systems according to the present invention may be further illustrated by way of the following examples. 
     Example 1 
     0.07 kg/s of CO 2  comes from the gas purification unit or a gas separation station of a geothermal power plant. The initial pressure of the gas is 30 bar. For the transportation of the gas to the injection well a pipe is selected with outer diameter (OD) 40 mm, resulting in a pressure drop of 1.45 bar. Including other pressure losses it is assumed that the pressure at the well head is 28 bar. For the injection a pipe with OD 32 mm is selected resulting in pressure drop of 0.41 bar, but due to gravity the pressure head at the merging point will increase by 1.1 bar and the pressure at the merging point will be 28.6 bar. 
     The injection pipe is a pipe with OD 75 mm and needs a volumetric flow rate of 1.94 kg/s of water to dissolve the gaseous carbon dioxide. The pressure drop under those conditions is 0.51 bar/100 m. Therefore, the water column in the injection pipe will be approximately 13 m above the water level in the well due to the pressure drop down to the merging point. It is not necessary to change the location of the merging point due to this increased pressure. However, the water column in the pipe will rise further by approximately 15 m due to pressure drop in the pipe below the merging point and therefore the merging point must be elevated accordingly. Thus, the water level will be approximately 28 m above the water level in the well. To have 25 bar pressure at the merging point it must be 255 m below the water level in the pipe or 227 m below the water level in the well. 
     Under those conditions the pressure drop in the merging can be up to 3.6 bar. The water downward flow velocity at the merging point will be approximately 0.95 m/s. The same procedure was applied with lower water flow rate at 1.73 kg/s resulting in downward flowing velocity at the merging point of 0.85 m/s. This lower flow rate, however, prevented an efficient downward movement of all gas bubbles resulting in untimely shutdown of the process. If the inner diameter of the water pipe is diminished at the merging point, a sufficient downward water flowing velocity can be achieved even at the reduced water flow rate of 1.73 kg/s ensuring full dissolution of the gas bubbles. Such a design will reduce the water demand of this gas abatement method. 
     Example 2 
     In this example, the partial pressure of carbon dioxide is selected to be 25 bar downhole. This means saturation at 25 bar pressure or 36 g CO 2  pr. kg water at 17° C. At this temperature and pressure the volume of carbon dioxide is approximately 20 times the volume of the equivalent mass of water at atmospheric pressure. For the water to be able to pull the gas downwardly, the volume of the gas should not exceed the volume of the water, preferably be much smaller. For the water to be able to bring the gas downward in the pipe, the water pressure at the gas release point (merging point) should preferably be near the saturation pressure of 25 bar. If however a sufficient volumetric water flow rate is maintained it is possible to have the pressure lower. Part of the gas will dissolve in the water and the remaining gas will form small bubbles and travel with the water down the pipe. 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 has been dissolved. 
     Example 3 
     In this embodiment, shown in  FIG. 10 , a monitoring well  610  is interlinked to the injection well  612  via a flow path  614 , which may e.g. be a fracture in the geological reservoir. The implementation of this monitoring well  610  is to estimate the mineralization capacity of the CO 2 . The step of estimating comprises using one or more tracer substances for tracing the CO 2  gas, or the water, or the carbon. Thus, one or more types of tracers may be added via an appropriate tracer source for tracing one or more of these in a controllable way such that the molar ratio between the CO 2  gas, or the water, or the carbon, and the tracer substance(s) is pre-determined, i.e. the molar ratio is prefixed. This means that only one tracer can be used for tracing e.g. only CO 2 , or only C, or only water, or a combination thereof. As an example, SF 5 CF 3  tracer, SF 6  tracer or Rhodamine tracer may be implemented to track the dilution between the injected fluid and the ambient water in the reservoir as well as to characterize the advective and dispersive transport of the CO 2  saturated solution in the storage reservoir. C-14 tracer concentration injected with the CO 2  can on the other hand change as a result of CO 2 -water-rock interaction and therefore allows for estimation the degree of mineralization for the injected CO 2  in turns of mass balance calculations. A monitoring equipment may be provided (not shown here) for monitoring the molar ratio between the CO 2  gas, or the water, or the carbon, and the tracer substance(s) in this monitoring well  610  as a consequence of injecting said dissolved CO 2 . As already mentioned, the monitoring well  610  is interlinked to the injection well  612  via said flow path such that at least a part of the injected water mixed with the dissolved CO 2  and said tracer substance(s) flows to the monitoring well  610  via said flow path  614 . By comparing the molar ratio at the monitoring well  610  and the injection well  612  an abatement indicator can be determined indicating the amount of CO 2  sequestration via water-rock reactions. Accordingly, if the tracer used is SF 5 CF 3  tracer and the molar ratio between [SF 5 CF 3 ]/[CO 2 ] is 1 at the injection well  612  but 2 at the monitoring well  610 , this would clearly indicate that half of the CO 2  has been subjected to chemical reactions with the rock via said water-rock reactions. 
     Such a monitoring well  610  may just as well be implemented in relation to the embodiment shown in  FIG. 4 . 
     Example 4 
       FIG. 5  shows one embodiment of a method according to the present invention of abating hydrogen sulfide in a geothermal reservoir, where the mineralization capacity of the H 2 S is estimated. This method may either occur prior to said method steps in  FIG. 1  or be implemented as a monitoring method performed at some later time. 
     In step (S 4 )  301 , a tracer substance such as KI is dissolved in addition to the dissolved H 2 S in a controllable way so that the molar ratio between H 2 S and the tracer substance will be pre-determined. 
     In step (S 5 )  303 , a monitoring is performed, in response to injecting the dissolved H 2 S and the dissolved tracer substance into the injection well, of the molar ratio between the H 2 S and the tracer substance in a monitoring well. This monitoring is a well that is interlinked to the injection well via a flow path such as cracks or fracture in the rock such that at least a part of the injected water mixed with said dissolved H 2 S as said tracer substance flows to the monitoring well via this flow path. This monitoring includes then measuring the concentration of the H 2 S and the tracer substance and based thereon the molar ratio between the H 2 S and the tracer substance at the monitoring well. 
     In step (S 6 )  305 , an abatement indicator is determined indicating the amount of H 2 S abatement via water-rock reactions based on comparing the molar ratio between the H 2 S and the tracer substance at the monitoring well with the corresponding molar ratio at the injection well. For example if the H 2 S/tracer molar ratio that goes into the injection well is 1.0 but 0.5 at the monitoring well, this would indicate that half of the dissolved H 2 S becomes mineralized in the geothermal reservoir via water-rock reactions. However, to improve the method even further, it would be preferred to perform a correction taking into account oxidation of H 2 S to other sulfur species, which could cause uncertainty. 
     Example 5 
       FIG. 6  depicts schematically the method in  FIG. 5  showing an injection well  400  where water  409  is continuously being pumped into the well  400 . The total depth of such a well can be several kilometers. As shown here, the well is partly filled with water, where the water surface  406  is close to the closing cap of the casing  401  of the injection well. Due to continuous pumping of water, a water stream is formed in the well extending downward into the hole, where some of the water will flow into the geothermal reservoir  403  in a direction as indicated by the arrow  404 . As depicted here, the injection well includes a casing  401  such as a steel pipe which seals the well (e.g. seals it from fresh groundwater above the geothermal reservoir). The height of such a casing  401  can vary from a few hundred meters up to more than 1000 meters. As shown here, the remaining part of the injection well is in the rock  402 . The water-rock reactions that occur in the geothermal reservoir is indicated in the expanded view of  404  showing a flow path of the dissolved H 2 S in the rock, where the dissolved H 2 S reacts chemically with metal ions (Me)  407  in rock and forms Me sulfides  408 . If e.g. the Me is Fe the Me sulfide will be Fe-sulfide. 
     The temperature of the water  409  being pumped into the well will, if the water source is a geothermal well, typically be around 100° C., but preferably it is colder since then less water would be needed to dissolve the H 2 S than with hot water. This, however, depends on the water source, i.e. whether a fresh water source is being used (cold water) instead of geothermal water source. 
     Example 6 
       FIG. 9  depicts graphically an embodiment of a system  500  according to the present invention for abating hydrogen sulfide (H 2 S) in a geothermal reservoir  501 . The system comprises a H 2 S gas pipeline  502 , a wellhead  509 , water inlet  503 , an injection pipe  506 , a sparger  507 , a mixer  508  and an outer pipe  504 . The H 2 S is conducted to the wellhead  509  under high pressure and into the injection well  510  via the 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 positioned at depth h1+h2. In this embodiment, the volumetric flow rate of water (liters/second) into the injection well  510  is controlled via a valve  511 , where the water is pumped into the space between the injection pipe  506  and the outer pipe  505 . 
     The depth at the open of the injection pipe at depth h1 is selected such that the hydraulic pressure of the water at this depth is slightly less than the H 2 S gas pressure in the injection pipe. This is to ensure that the H 2 S gas can go into the water. Below the site of the injection of the H 2 S gas at depth h1+Δh with Δh«h1 the hydraulic pressure of the water is larger than the internal pressure of the dissolved H 2 S. 
     The water flow into the space between the injection pipe  506  and the outer pipe  504  is selected such that the volumetric flow rate and hence velocity of the water (as indicated by the arrows) is larger than the upwardly pointing velocity of the H 2 S gas due to the buoyant force on the H 2 S gas at the open end of the injection pipe. Hence, as H 2 S bubbles move downward, the hydraulic pressure increases and bubbles become smaller resulting in reduced upward pointing velocity of the bubbles. A preferred condition is when the bubbles are small since then the upward travelling velocity of the bubbles is small and also the total surface area is larger resulting in enhanced dissolution rate. 
     In this embodiment, the sparger  507  is placed at the open end of the injection pipe  506  for maximizing the interfacial area between the H 2 S gas and the water. By doing so, the H 2 S gas bubbles will be equally distributed within the water, and further, the average diameter of the bubbles will be reduced causing said maximization of the interfacial area between the H 2 S gas and the water. 
     Below the sparger is the mixer  508 . The role of the mixer is to mix the dissolved H 2 S with the water so as to obtain a uniform mixing of the H 2 S gas in the water and dissolving any remaining H 2 S gas bubbles in the water. Accordingly, more turbulence will be created, which will enhance the dissolution rate of H 2 S gas further. Also, large H 2 S gas bubbles will be split into smaller gas bubbles, which will also enhance the dissolution rate of the H 2 S. 
     Example 7 
       FIG. 10  depicts graphically another embodiment of a system  600  according to the present invention for abating inter alia hydrogen sulfide (H 2 S) in a geothermal reservoir. In this embodiment, a monitoring well  610  is interlinked to the injection well  612  via a flow path  614 , which may e.g. be a fracture in the geothermal reservoir. The implementation of this monitoring well  610  is to estimate the mineralization capacity of the H 2 S as discussed previously in relation to  FIG. 5 . 
     Example 8 
       FIG. 11  depicts graphically yet another embodiment of a system  700  according to the present invention for abating hydrogen sulfide (H 2 S) in a geothermal reservoir. In this embodiment the H 2 S is transferred down to the injection well  703  in a separate pipe  701  outside the water injection pipe  705 . Since the pipe is fastened at the wellhead (not shown here) the depth of the merging point cannot be changed if conditions change such as changed water flow. It is thus 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 lower pressure drop in the injection pipe and therefore higher water flow rate can be maintained which makes it easier to pull the gas bubbles down the pipe. 
     Example 9 
     A significant part of the security risk associated with geologic carbon storage occurs because gaseous CO 2  is prone to escape back to the surface and leak into the atmosphere or into overlying fresh-water aquifers. This is particularly problematic when the storage is attempted in porous geological formations. 
     The present set of experiments were performed at the geothermal plant in Hellisheidi, Iceland. The rocks at the Hellisheidi injection site are of ultramafic to basaltic composition and highly permeable in both lateral and vertical directions (300 and 1700×10 −15  m 2 , respectively) and an estimated 8,5% porosity. 
     Using a device as the one depicted in  FIG. 4  CO 2  and H 2 O was injected at a target mass rate of 70 and 1940 g respectively. The CO 2  and H 2 O was released at a depth of 330-360 m. At this depth, CO 2  was released via a sparger in the form of small gas bobbles into the flowing H 2 O. The CO 2 /H 2 O mixture was carried from the sparger via a mixing pipe extending down to 540 m where it was released to the subsurface rocks. Approximately half the way (approximately at 420 m) a static mixer was located to aid CO 2  dissolution. Over a period of 3 months approximately 175 t of CO 2  together with approximately 5000 t H 2 O were injected into the subsurface at the site. 
     Verification of the complete dissolution of CO 2  during its injection was performed by digital downhole camera (showing no CO 2  bubbles and by high-pressure well water sampling using a custom made bailer. 
     Images show the well fluid to be void of gas bubbles consistent with the complete dissolution of CO 2  1.5 m above the fluid outlet at 540 m. 
     12 well water samples were analyzed for total dissolved inorganic carbon and 6 of the 12 were measured for in-situ pH. In each case the dissolved inorganic carbon concentration of the sample fluid was on average within 5% of the 0.82±2% mol/kg concentration based on measured CO 2  and H 2 O mass flow rates into the well and the fluid pH was 3.89±0.1 confirming the complete dissolution of the CO 2  during its injection. 
     Thus if injected into the subsurface as a dissolved phase, CO 2  is far less likely to escape back to the atmosphere due to its lack of bubble-formation or buoyancy (Ref. 15: Gilfillan et al., 2009). 
     Example 10 
     A further experimental injection of CO 2 /H 2 S was carried out with the following parameters: 
     
       
         
           
               
               
               
               
             
               
                   
                   
               
               
                   
                 Water 
                 CO 2   
                 H 2 S 
               
               
                   
                   
               
             
            
               
                   
               
            
           
           
               
               
               
               
               
            
               
                   
                 Temperature (° C.) 
                 23 
                 18 
                 18 
               
               
                   
                 Pressure at mixing 
                   
                 18 
                 6 
               
               
                   
                 point (bar-a) 
               
               
                   
                 Volume flow rate at 
                 1.4 
                 10.9 
                 3.6 
               
               
                   
                 atmospheric pressure (l) 
               
               
                   
                 Mass flow rate (g/s) 
                 1.4 
                 27.4 
                 7.1 
               
               
                   
                 Water downward flow 
                 1.04 
               
               
                   
                 velocity above merging 
               
               
                   
                 point (m/s) 
               
               
                   
                 Water downward flow 
                 0.65 
               
               
                   
                 velocity below merging 
               
               
                   
                 point (m/s) 
               
               
                   
                   
               
            
           
         
       
     
     In this example, the partial pressure of carbon dioxide and hydrogen sulphide was selected to be 18 bar and 6 bar downhole. 
     The pH value of the water with the dissolved CO 2  will decrease with increasing CO 2  pressure as this increases the CO 2  content of the water. In one experiment the depth was selected such that the pH value was around 3.2. This corresponded to a depth of 520 m. As is clear from the table above, the downward velocity of the water in this example was app. 0.7 m/s. Changing the downward velocity of the water to app. 0.3 m/s resulted in failure. 
     In the claims, the word “comprising” does not exclude other elements or steps, and the indefinite article “a” or “an” does not exclude a plurality. A single processor or other unit may fulfill the functions of several items recited in the claims. The mere fact that certain measures are recited in mutually different dependent claims does not indicate that a combination of these measured cannot be used to advantage. Any reference signs in the claims should not be construed as limiting the scope. 
     REFERENCES 
     All of which are hereby incorporated in their entirety by reference.
     Ref. 1: Broecker W. S., 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, E. H., Cole, D   Ref. 2: Barbier, E. (2002) Geothermal Energy Technology and Current Status: an Overview. Renewable and Sustainable Energy Reviews, 6, p. 3-65   Ref. 3: Arnórsson, S. (1995a) Hydrothermal systems in Iceland: Structure and conceptual models. 1. High-temperature areas. Geothermics 24, 561-602   Ref. 4: Arnórsson, S. (1995b) Hydrothermal systems in Iceland: Structure and conceptual models. 2. Low-temperature areas. Geothermics 24, 603-629   Ref. 5: Kerr, T. M., 2007. Legal aspects of storing CO2: update and recommendations. OECD/IEA   Ref. 6: Hawkins, D. G., 2004. No exit: thinking about leakage from geologic carbon storage sites, Energy 29, 1571-1578   Ref. 7: Benson, S. M., Cole, D. R., 2008. CO2 sequestration in deep sedimentary formations. Elements 4, 325-331   Ref. 8: Mineral sequestration of carbon dioxide in basalt: A pre-injection overview of the CarbFix project; Gislason S R, Wolff-Boenisch D, Stefansson A, et al.; INTERNATIONAL JOURNAL OF GREENHOUSE GAS CONTROL, Vol. 4, Issue: 3, Pages: 537-545, Pub. May 2010   Ref. 9: Sanopoulos, D. and Karabelas A. (1997). H 2 S abatement in geothermal plants: Evaluation of Process Alternatives. Energy Sources, 19, 63-77)   Ref. 10: Hibara, Y., Araki, K., Tazaki, S. and Kondo, T. (1990) Recent technology of geothermal plants. Geothermal Resource Council Transactions 14, Part II: 1015-1024   Ref. 11: Oelkers, E., Gislason, S., 2001. The mechanism, rates and consequences of basaltic glass dissolution: I. an experimental study of the dissolution rates of basaltic glass as a function of aqueous al, si and oxalic acid concentrations at 25c and pH=3 and 11. Geochim. Cosmochim. Acta 65, 3671-3681   Ref. 12: Global CCS Institute (2011) Economic Assessment of Carbon Capture and Storage Technologies 2011 update   Ref. 13: Rubin et al. (2015) Int. J. Greenh. Gas Control 40, 378-400   Ref. 14: Hu and Zhai (2017) Int. J. Greenh. Gas Control 65, 23-31   Ref. 15: Gilfillan et al. (2009) Nature 458, 614-618   Ref. 16: Sigfusson et al. (2015) Int. J. Greenh. Gas Control 37, 213-219   Ref. 17: Gunnarson et al (2018) Int. J. Greenh. Gas Control 79, 117-126