A METHOD OF ABATING CARBON DIOXIDE AND HYDROGEN SULFIDE

Abstract

This invention relates to a method and a system of abating carbon dioxide (CO.sub.2) and/or hydrogen sulfide (H.sub.2S) in a geological reservoir. Water is pumped or transferred from a water source to an injection well. The gasses are merged with the water under conditions where the hydraulic pressure of the water is less than the pressure of CO.sub.2 and/or H.sub.2S gas at the merging point. The water with CO.sub.2 and/or H.sub.2S gas bubbles is transferred further downwardly at a certain velocity higher than the upward flow velocity of said CO.sub.2 and/or H.sub.2S gas bubbles ensuring downward movement of gas bubbles resulting in full dissolution of said CO.sub.2 and/or H.sub.2S in the water due to elevating pressure. The complete dissolution ensures a lowered pH of the water entering a geological (e.g. geothermal) reservoir which is needed to promote mineral reactions leading to CO.sub.2 and H.sub.2S abatement This abatement may be quantified by dissolving a tracer substance in a predetermined molar ratio to said dissolved CO.sub.2 and/or H.sub.2S and monitored in a monitoring well.

Claims

1. A method of abating carbon dioxide (CO.sub.2) and/or hydrogen sulfide (H.sub.2S), 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.sub.2 and/or H.sub.2S rich gas into an injection pipe (206) of an injection well (210) thereby creating a CO.sub.2 and/or H.sub.2S rich gas stream comprising pressurized CO.sub.2, and/or pressurized H.sub.2S, in said injection pipe (206) dissolving substantially all of said pressurized CO.sub.2 and/or H.sub.2S gas of said CO.sub.2 and/or H.sub.2S rich gas stream in said pressurized water stream by; merging said pressurized water stream and said CO.sub.2 and/or H.sub.2S 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.sub.2 and/or H.sub.2S, p(CO.sub.2) and/or p(H.sub.2S), in said injection pipe (206), and transferring said water stream from said depth h1≥0 to a depth h1+h2, where (h1+h2)>h1, at a downward flow velocity, v(W), which at h1+h2 is higher than the upward flow velocity of said CO.sub.2 and/or H.sub.2S gas, v(CO.sub.2) and/or v(H.sub.2S), resulting from the buoyant force on bubbles of CO.sub.2 and/or H.sub.2S gas in said water stream at said depth h1+h2 keeping the resulting pH value of said pressurized water stream containing said dissolved CO.sub.2 and or H.sub.2S between about 2 and 4, preferably between about 2.5 and 3.5, more preferably about 3.2 injecting said pressurized water stream comprising dissolved CO.sub.2 and/or H.sub.2S into a geological reservoir comprising reactive rocks at h1+h2 or at a depth>(h1+h2).

2. A method according to claim 1, wherein the geological reservoir is a geothermal reservoir.

3. A method according to claim 1, further including increasing the interfacial area between the CO.sub.2 and/or H.sub.2S to be dissolved in said water stream by fitting said injection pipe (206) with a means for sparging (207) at the merging point at depth h1≥0.

4. A method according to claim 1, wherein 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.

5. A method according to claim 4, wherein said outer pipe (205), comprising said pressurized water stream, has an open end at said depth h1+h2.

6. A method according to claim 1, wherein the pressure of CO.sub.2, p(CO.sub.2), at the merging point at depth h1 is between about 20-36 bar, preferably between about 22-34 bar, more preferably between about 24-32 bar, most preferably about 24.5 bar.

7. A method according to claim 1, wherein the pressure of H.sub.2S, p(H.sub.2S), at the merging point at depth h1 is between about 4-8 bar, preferably between about 5-7 bar, more preferably between about 5.5-6.5 bar, most preferably about 6 bar.

8. A method according to claim 1, further comprising the steps of: dissolving a tracer substance, in a predetermined molar ratio compared to said dissolved CO.sub.2 and/or H.sub.2S, 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.sub.2 and/or H.sub.2S 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.sub.2 and/or H.sub.2S and tracer substance at said monitoring well (610) and establishing based thereon the molar ratio between CO.sub.2 and/or H.sub.2S and tracer substance at said monitoring well (610), and determining an abatement indicator indicating the degree of CO.sub.2 and/or H.sub.2S abatement based on comparing the molar ratio between CO.sub.2 and/or H.sub.2S 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).

9. A system for abating carbon dioxide (CO.sub.2) and/or hydrogen sulfide (H.sub.2S), 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.sub.2 and/or H.sub.2S rich gas into said injection pipe (206) thereby creating a CO.sub.2 and/or H.sub.2S rich gas stream comprising pressurized CO.sub.2, and/or pressurized H.sub.2, in said injection pipe (206) means for merging said pressurized water stream and said CO.sub.2 and/or H.sub.2S 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.sub.2 and/or H.sub.2S, p(CO.sub.2) and/or p(H.sub.2S), in said injection pipe (206) means for transferring said water stream from said depth h1≥0 to a depth h1+h2, where (h1+h2)>h1, at a downward flow velocity, v(W), which at h1+h2 is higher than the upward flow velocity of said CO.sub.2 and/or H.sub.2S gas, v(CO.sub.2) and/or v(H.sub.2S), resulting from the buoyant force on bubbles of CO.sub.2 and/or H.sub.2S gas in said water stream at said depth h1+h2 means for keeping the resulting pH value of said pressurized water stream containing said CO.sub.2 and or H.sub.2S 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 containing said CO.sub.2 and/or H.sub.2S into a geological reservoir comprising reactive rocks at h1+h2 or at a depth>(h1+h2).

10. A system according to claim 9 further comprising means for sparging (207) fitted onto said injection pipe (206) at the merging point at depth h1≥0.

11. A system according to claim 9, wherein said injection pipe (206) extends down into said outer pipe (205) and has an open end at said depth h1≥0.

12. A system according to claim 9, wherein said outer pipe (205) has an open end at said depth h1+h2.

13. A system according to claim 9, further comprising: means for dissolving a tracer substance, in a predetermined molar ratio compared to said dissolved CO.sub.2 and/or H.sub.2S, in said pressurized water stream at said depth h1 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.sub.2 and/or H.sub.2S 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.sub.2 and/or H.sub.2S and tracer substance at said monitoring well (610) and establishing based thereon the molar ratio between CO.sub.2 and/or H.sub.2S and tracer substance at said monitoring well (610), and means for determining an abatement indicator indicating the degree of CO.sub.2 and/or H.sub.2S abatement based on comparing the molar ratio between CO.sub.2 and/or H.sub.2S 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).

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0072] Hereinafter a number of embodiments of the invention are described, by way of example only, with reference to the drawings, in which

[0073] FIG. 1 shows a flowchart of a method according to the present invention of abating CO.sub.2 and/or H.sub.2S in a geological reservoir.

[0074] FIG. 2 shows a schematic representation of host rock and formation fluid interaction during in situ CO.sub.2 mineral sequestration.

[0075] FIG. 3 shows a flowchart of an embodiment of a method according to the present invention indicating in more details how the dissolved CO.sub.2 and/or H.sub.2S is injected into the geological reservoir.

[0076] FIG. 4 shows a system according to the present invention for storing carbon dioxide (CO.sub.2) in a geological reservoir.

[0077] FIG. 5 shows a flowchart of an embodiment of a method according to the present invention of abating hydrogen sulfide (H.sub.2S) in a geological reservoir.

[0078] 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.

[0079] 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).

[0080] FIG. 8 shows an expanded view of the first quarter of FIG. 7.

[0081] FIGS. 9-11 depicts graphically different embodiments of a system according to the present invention for abating hydrogen sulfide (H.sub.2S) and carbon dioxide (CO.sub.2), in a geological reservoir.

DESCRIPTION OF EMBODIMENTS

[0082] FIG. 1 shows a flowchart of a method according to the present invention of abating CO.sub.2 and/or H.sub.2S 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.

[0083] In a first step (S1) 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.

[0084] In a second step (S2) 103, CO.sub.2 and/or H.sub.2S gas is merged with the water at a merging point where the hydraulic pressure of the water is lower than the pressure of CO.sub.2 and/or H.sub.2S, 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.sub.2 and/or H.sub.2S relatively shortly after the gasses have been injected into the water.

[0085] In step (S3) 105, the water with the dissolved CO.sub.2 and/or H.sub.2S is injected into the geological reservoir.

[0086] In one embodiment, step (S2) 103 comprises conducting the CO.sub.2 and/or H.sub.2S 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.sub.2 and/or H.sub.2S gas pressure in the injection pipe. This is simply to enable the CO.sub.2 and/or H.sub.2S 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.sub.2 and/or H.sub.2S gas at depths larger than h1 is provided, thereby ensuring that the water is transferred to depths larger than h1 without the CO.sub.2 and/or H.sub.2S escaping the water.

[0087] In a preferred embodiment the pressure of the CO.sub.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.sub.2 is relatively low which will enhance the CO.sub.2 water rock reactions in the geological reservoir.

[0088] One of the important aspects of the present invention is the dissolution of CO.sub.2 (and/or H.sub.2S) in water before it is dispersed as a single-phase fluid into the pore space of reactive rock formations. The CO.sub.2 dissolves to form carbonic acid (H.sub.2CO.sub.3), which can dissociate into bicarbonate (HCO.sub.3) and carbonate (CO.sub.3.sup.2-) according to:

CO.sub.2(g)═CO.sub.2(aq)  (1a)

CO.sub.2(aq)+H.sub.2O═H.sub.2CO.sub.3(aq)  (1b)

H.sub.2CO.sub.3 (aq)=HCO.sub.3.sup.−+H.sup.+  (1c)

HCO.sub.3.sup.−=CO.sub.3.sup.2−+H.sup.+  (1d)

[0089] For example, plagioclase ((Ca, Na)Al.sub.1.70Si.sub.2.30O.sub.8), olivine ((Mg, Fe).sub.2SiO.sub.4) and pyroxene ((Ca, Mg, Fe).sub.2SiO.sub.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.sup.2+, Mg.sup.2+ and Fe.sup.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.sub.1.70Si.sub.2.30O.sub.8(s)+6.8H.sup.+═(Ca.sup.2+,Na.sup.+)+1.70Al.sup.3++2.3SiO.sub.2(aq)+3.4H.sub.2O.sub.(l)  (2)

(Mg,Fe).sub.2SiO.sub.4(s)+4H.sup.+=2(Mg,Fe).sup.2++SiO.sub.2(aq)+2H.sub.2O.sub.(l)  (3)

(Ca,Mg,Fe).sub.2SiO.sub.3+2H.sup.+=2(Ca,Mg,Fe).sup.2++SiO.sub.2(aq)+H.sub.2O.sub.(l)  (4)

SiAl.sub.0.36Fe.sub.0.19Mg.sub.0.28Ca.sub.0.26Na.sub.0.08K.sub.0.008O.sub.3.31+2.58H.sup.+═SiO.sub.2(aq)+0.36Al.sup.3++0.19Fe.sup.2++0.28Mg.sup.2++0.26Ca.sup.2++0.08Na.sup.++0.008K.sup.2++1.30H.sub.2O.sub.(l)  (5)

[0090] As dissolution reactions 2-5 proceed in the subsurface after CO.sub.2 and/or H.sub.2S injection, protons (H.sup.+) are consumed and pH of formation fluids increases.

[0091] 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.sub.2 mineral sequestration after CO.sub.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.

[0092] 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).sup.2++CO.sub.3.sup.2−═(Ca,Mg,Fe)CO.sub.3(s)  (6)

[0093] Calcite (CaCO.sub.3), dolomite (CaMg(CO.sub.3).sub.2), magnesite (MgCO.sub.3) and siderite (FeCO.sub.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.sub.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.

[0094] FIG. 3 shows a flowchart of an embodiment of a method according to the present invention indicating in more details how said step (S3) 105 is performed.

[0095] In step (S3′) 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.sub.2 and/or H.sub.2S gas to be dissolved.

[0096] In step (S3″) 203, the CO.sub.2 and/or H.sub.2S 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.sub.2 and/or H.sub.2S gas. The pressure of the water is in one embodiment around 6 bars or somewhat lower than the pressure of the CO.sub.2 and/or H.sub.2S gas. In this embodiment, said step (S3) 105 of injecting the dissolved H.sub.2S 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.sub.2 and/or H.sub.2S. The reason of doing so is to ensure that when the water with the dissolved CO.sub.2 and/or H.sub.2S comes out from the open end of the injection pipe, the surrounding pressure will be larger than the pressure of the dissolved CO.sub.2 and/or H.sub.2S. By doing so the dissolved CO.sub.2 and/or H.sub.2S will stay in a dissolved state until the CO.sub.2 and/or H.sub.2S mineralizing water rock reactions start. At the same time the low pH of the water containing the dissolved CO.sub.2 and/or H.sub.2S 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.sub.2S gas and the water and/or mixing the dissolved H.sub.2S with the water so as to obtain a uniform mixing of the H.sub.2S in the water and dissolving any remaining H.sub.2S gas bubbles in the water.

[0097] In one embodiment, said step (S3) 105 of dissolving CO.sub.2 and/or H.sub.2S gas in the water comprises conducting the CO.sub.2 and/or H.sub.2S 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.sub.2 and/or H.sub.2S gas pressure in the injection pipe. Preferably, the hydraulic pressure is slightly less that the CO.sub.2 and/or H.sub.2S gas pressure in the pipeline at this open end, firstly to ensure that the CO.sub.2 and/or H.sub.2S 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.sub.2 and/or H.sub.2S has travelled the distance h2 downwardly), is larger than the pressure of the dissolved CO.sub.2 and/or H.sub.2S in the water. This injection pipe may e.g. be a pipe that extends from a gas separation station where CO.sub.2 and/or H.sub.2S gas is separated from geothermal gas and subsequently conducted to the injection well via a pipeline.

[0098] FIG. 4 depicts graphically an embodiment of a system 200 according to the present invention for storing carbon dioxide CO.sub.2 in a geological reservoir 201. The system comprises a CO.sub.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.sub.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.

[0099] 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.sub.2 gas pressure in the injection pipe. This is to ensure that the CO.sub.2 gas can go into the water. Further downwards of the injection of the CO.sub.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.sub.2. This is to ensure that the pressure of the dissolved CO.sub.2 will be less than the hydraulic pressure so that it stays dissolved in the water.

[0100] 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.sub.2 gas bubbles due to the buoyant force on the CO.sub.2 gas at the open end of the injection pipe. Hence, as CO.sub.2 bubbles move downward, the hydraulic pressure increases, CO.sub.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.

[0101] 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.

[0102] 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.sub.2 gas and the water. By doing so, the CO.sub.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.sub.2 gas and the water.

[0103] Below the sparger is the mixer 208, the role of which is to mix the dissolved CO.sub.2 with the water so as to obtain a uniform mixing and dissolve any remaining CO.sub.2 gas bubbles in the water. Accordingly, more turbulence will be created, which will enhance the dissolution of CO.sub.2 gas further. Also, large CO.sub.2 gas bubbles will be split into smaller gas bubbles, which will also enhance the dissolution rate of the CO.sub.2.

[0104] 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.sub.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.sub.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.sub.2 will be around 3.2, but the pH value decreases with increasing CO.sub.2 pressure. This corresponds when h1+h2≈520 m. It is at this depth that the dissolved CO.sub.2 leaves the system 200 and the sequestration of the CO.sub.2 in basaltic rocks starts. The lower the pH value is, the higher will the dissolution rate be within the basaltic rock.

[0105] 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.sub.2/H.sub.2S. This is significantly lower than the price (USD 35 to USD 143 pr. ton CO.sub.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.

[0106] 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.

[0107] Referring to the accompanying figures the present invention in particular relates to a method of abating carbon dioxide (CO.sub.2) and/or hydrogen sulfide (H.sub.2S), comprising the steps of: [0108] 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), [0109] pumping a CO.sub.2 and/or H.sub.2S rich gas into a gas injection pipe (206) of an injection well (210) thereby creating a CO.sub.2 and/or H.sub.2S rich gas stream comprising pressurized CO.sub.2, and/or pressurized H.sub.2, in said injection pipe (206) [0110] dissolving substantially all of said pressurized CO.sub.2 and/or H.sub.2S gas of said CO.sub.2 and/or H.sub.2S rich gas stream in said pressurized water stream by merging said pressurized water stream and said CO.sub.2 and/or H.sub.2S 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.sub.2 and/or H.sub.2S, p(C) and/or p(H), in said injection pipe (206) [0111] keeping said dissolved CO.sub.2 and/or H.sub.2S in solution in said water stream by transferring said water stream from said depth h1≥0 to a depth h1+h2, where (h1+h2)>h1, at a downward flow velocity, v(W), which at h1+h2 is higher than the upward flow velocity of said CO.sub.2 and/or H.sub.2S gas, v(C) and/or v(H), resulting from the buoyant force on bubbles of CO.sub.2 and/or H.sub.2S gas in said water stream at said depth h1+h2 [0112] injecting said pressurized water stream comprising dissolved CO.sub.2 and/or H.sub.2S into a geological reservoir comprising reactive rocks at h1+h2 or at a depth>(h1+h2).

[0113] In a particular preferred embodiment of a method according to the invention the geological reservoir is a geothermal reservoir.

[0114] In a particular preferred embodiment of a method according to the invention the interfacial area between the CO.sub.2 and/or H.sub.2S 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.

[0115] 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.

[0116] 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.

[0117] 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.

[0118] 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.

[0119] In a yet further particularly preferred embodiment of a method according to the invention the pressure of CO.sub.2, p(C O.sub.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.

[0120] In a yet further particularly preferred embodiment of a method according to the invention the pressure of H.sub.2S, (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.

[0121] 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.sub.2 and or H.sub.2S 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.

[0122] In a yet further particularly preferred embodiment of a method according to the invention, the method further comprises the steps of:

[0123] dissolving a tracer substance, in a predetermined molar ratio compared to said dissolved CO.sub.2 and/or H.sub.2S, in said pressurized water stream at said depth h1≥0 in said outer pipe (205) in said injection well (210/612),

[0124] 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.sub.2 and/or H.sub.2S 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),

[0125] measuring the concentration of CO.sub.2 and/or H.sub.2S and tracer substance at said monitoring well (610) and establishing based thereon the molar ratio between CO.sub.2 and/or H.sub.2S and tracer substance at said monitoring well (610), and

[0126] determining an abatement indicator indicating the degree of CO.sub.2 and/or H.sub.2S abatement based on comparing the molar ratio between CO.sub.2 and/or H.sub.2S 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).

[0127] Referring to the accompanying figures the present invention furthermore in particular relates to a system for abating carbon dioxide (CO.sub.2) and/or hydrogen sulfide (H.sub.2S), comprising:

[0128] an injection well (210)

[0129] an outer pipe (205) extending downwardly inside said injection well (210)

[0130] 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),

[0131] means for pumping a CO.sub.2 and/or H.sub.2S rich gas into said injection pipe (206) thereby creating a CO.sub.2 and/or H.sub.2S rich gas stream comprising pressurized CO.sub.2, and/or pressurized H.sub.2, in said injection pipe (206)

[0132] means for merging said pressurized water stream and said CO.sub.2 and/or H.sub.2S 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.sub.2 and/or H.sub.2S, p(C) and/or p(H), in said injection pipe (206)

[0133] means for transferring said water stream from said depth h1≥0 to a depth h1+h2, where (h1+h2)>h1, at a downward flow velocity, v(W), which at h1+h2 is higher than the upward flow velocity of said CO.sub.2 and/or H.sub.2S gas, v(C) and/or v(H), resulting from the buoyant force on bubbles of CO.sub.2 and/or H.sub.2S gas in said water stream at said depth h1+h2

[0134] means for keeping the resulting pH value of said pressurized water stream containing said dissolved CO.sub.2 and or H.sub.2S between about 2 and 4, preferably between about 2.5 and 3.5, more preferably about 3.2

[0135] means for injecting said pressurized water stream comprising dissolved CO.sub.2 and/or H.sub.2S into a geological reservoir comprising reactive rocks at h1+h2 or at a depth>(h1+h2).

[0136] 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.

[0137] 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.

[0138] 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)>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.

[0139] 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.

[0140] 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.

[0141] In a yet further particularly preferred embodiment of a system according to the present invention, the system further comprises:

[0142] means for dissolving a tracer substance, in a predetermined molar ratio compared to said dissolved CO.sub.2 and/or H.sub.2S, in said pressurized water stream at said depth h1≥0 in said outer pipe (205) in said injection well (210/612),

[0143] a monitoring well (610)

[0144] a flow path (614), whereby at least a part of said pressurized water mixed with said dissolved CO.sub.2 and/or H.sub.2S and said tracer substance flows from said outer pipe (205) of said injection well (210/612) to said monitoring well (610),

[0145] means for measuring the concentration of CO.sub.2 and/or H.sub.2S and tracer substance at said monitoring well (610) and establishing based thereon the molar ratio between CO.sub.2 and/or H.sub.2S and tracer substance at said monitoring well (610), and

[0146] means for determining an abatement indicator indicating the degree of CO.sub.2 and/or H.sub.2S abatement based on comparing the molar ratio between CO.sub.2 and/or H.sub.2S 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).

[0147] The methods and systems according to the present invention may be further illustrated by way of the following examples.

Example 1

[0148] 0.07 kg/s of CO.sub.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.

[0149] 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.

[0150] 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

[0151] 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.sub.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

[0152] 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.sub.2. The step of estimating comprises using one or more tracer substances for tracing the CO.sub.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.sub.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.sub.2, or only C, or only water, or a combination thereof. As an example, SF.sub.5CF.sub.3 tracer, SF.sub.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.sub.2 saturated solution in the storage reservoir. C-14 tracer concentration injected with the CO.sub.2 can on the other hand change as a result of CO.sub.2-water-rock interaction and therefore allows for estimation the degree of mineralization for the injected CO.sub.2 in turns of mass balance calculations. A monitoring equipment may be provided (not shown here) for monitoring the molar ratio between the CO.sub.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.sub.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.sub.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.sub.2 sequestration via water-rock reactions. Accordingly, if the tracer used is SF.sub.5CF.sub.3 tracer and the molar ratio between [SF.sub.5CF.sub.3]/[CO.sub.2] is 1 at the injection well 612 but 2 at the monitoring well 610, this would clearly indicate that half of the CO.sub.2 has been subjected to chemical reactions with the rock via said water-rock reactions.

[0153] Such a monitoring well 610 may just as well be implemented in relation to the embodiment shown in FIG. 4.

Example 4

[0154] 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.sub.2S 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.

[0155] In step (S4) 301, a tracer substance such as KI is dissolved in addition to the dissolved H.sub.2S in a controllable way so that the molar ratio between H.sub.2S and the tracer substance will be pre-determined.

[0156] In step (S5) 303, a monitoring is performed, in response to injecting the dissolved H.sub.2S and the dissolved tracer substance into the injection well, of the molar ratio between the H.sub.2S 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.sub.2S as said tracer substance flows to the monitoring well via this flow path. This monitoring includes then measuring the concentration of the H.sub.2S and the tracer substance and based thereon the molar ratio between the H.sub.2S and the tracer substance at the monitoring well.

[0157] In step (S6) 305, an abatement indicator is determined indicating the amount of H.sub.2S abatement via water-rock reactions based on comparing the molar ratio between the H.sub.2S and the tracer substance at the monitoring well with the corresponding molar ratio at the injection well. For example if the H.sub.2S/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.sub.2S 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.sub.2S to other sulfur species, which could cause uncertainty.

Example 5

[0158] 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.sub.2S in the rock, where the dissolved H.sub.2S 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.

[0159] 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.sub.2S 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

[0160] FIG. 9 depicts graphically an embodiment of a system 500 according to the present invention for abating hydrogen sulfide (H.sub.2S) in a geothermal reservoir 501. The system comprises a H.sub.2S 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.sub.2S 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.

[0161] 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.sub.2S gas pressure in the injection pipe. This is to ensure that the H.sub.2S gas can go into the water. Below the site of the injection of the H.sub.2S gas at depth h1+Δh with Δh«h1 the hydraulic pressure of the water is larger than the internal pressure of the dissolved H.sub.2S.

[0162] 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.sub.2S gas due to the buoyant force on the H.sub.2S gas at the open end of the injection pipe. Hence, as H.sub.2S 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.

[0163] 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.sub.2S gas and the water. By doing so, the H.sub.2S 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.sub.2S gas and the water.

[0164] Below the sparger is the mixer 508. The role of the mixer is to mix the dissolved H.sub.2S with the water so as to obtain a uniform mixing of the H.sub.2S gas in the water and dissolving any remaining H.sub.2S gas bubbles in the water. Accordingly, more turbulence will be created, which will enhance the dissolution rate of H.sub.2S gas further. Also, large H.sub.2S gas bubbles will be split into smaller gas bubbles, which will also enhance the dissolution rate of the H.sub.2S.

Example 7

[0165] FIG. 10 depicts graphically another embodiment of a system 600 according to the present invention for abating inter alia hydrogen sulfide (H.sub.2S) 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.sub.2S as discussed previously in relation to FIG. 5.

Example 8

[0166] FIG. 11 depicts graphically yet another embodiment of a system 700 according to the present invention for abating hydrogen sulfide (H.sub.2S) in a geothermal reservoir. In this embodiment the H.sub.2S 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

[0167] A significant part of the security risk associated with geologic carbon storage occurs because gaseous CO.sub.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.

[0168] 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.sup.−15 m.sup.2, respectively) and an estimated 8,5% porosity.

[0169] Using a device as the one depicted in FIG. 4 CO.sub.2 and H.sub.2O was injected at a target mass rate of 70 and 1940 g respectively. The CO.sub.2 and H.sub.2O was released at a depth of 330-360 m. At this depth, CO.sub.2 was released via a sparger in the form of small gas bobbles into the flowing H.sub.2O. The CO.sub.2/H.sub.2O 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.sub.2 dissolution. Over a period of 3 months approximately 175 t of CO.sub.2 together with approximately 5000 t H.sub.2O were injected into the subsurface at the site.

[0170] Verification of the complete dissolution of CO.sub.2 during its injection was performed by digital downhole camera (showing no CO.sub.2 bubbles and by high-pressure well water sampling using a custom made bailer.

[0171] Images show the well fluid to be void of gas bubbles consistent with the complete dissolution of CO.sub.2 1.5 m above the fluid outlet at 540 m.

[0172] 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.sub.2 and H.sub.2O mass flow rates into the well and the fluid pH was 3.89±0.1 confirming the complete dissolution of the CO.sub.2 during its injection.

[0173] Thus if injected into the subsurface as a dissolved phase, CO.sub.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

[0174] A further experimental injection of CO.sub.2/H.sub.2S was carried out with the following parameters:

TABLE-US-00001 Water CO.sub.2 H.sub.2S 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)

[0175] In this example, the partial pressure of carbon dioxide and hydrogen sulphide was selected to be 18 bar and 6 bar downhole.

[0176] The pH value of the water with the dissolved CO.sub.2 will decrease with increasing CO.sub.2 pressure as this increases the CO.sub.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.

[0177] 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.

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