Method and system for removing H2S and CO2 from H2S and CO2 rich gas mixtures, such as geothermal non-condensable gas mixtures

Abstract

The present invention relates to a method and system for removing hydrogen sulfide (HS) and carbon dioxide (CO) from a gas mixture rich in HS and CO, such as a geothermal non-condensable gas mixture (NCG). The HS and CO gases are separated from the remaining gases contained in the HS and CO by pressurizing the gas stream and feeding it to an absorption tower, where the HS and CO are preferentially dissolved in a water stream, resulting in a water stream enriched in HS and CO. The HS and CO stream can then be reinjected into a geological reservoir or used to adjust the pH of another water stream of geological origin.

Description

[Technical field]

[0001] The present invention relates to a method for producing hydrogen sulfide (H 2 ) from geothermal non-condensable gas mixtures (NCG) and the like. 2 S) and carbon dioxide (CO 2 )-rich gas mixture to H 2 S and CO 2 This invention relates to a method for removing [Background technology]

[0002] Conventional geothermal power plants harness the heat of the earth by extracting a high-temperature mixture of steam and brine (geothermal water) from geothermal reservoirs that are characterized by thermal anomalies, permeable layers and fluids (Barbier, E. (2002) Geothermal Energy Technology and Current Status: an Overview. Renewable and Sustainable Energy Reviews, 6, p. 3-65). The fluids extracted from these geothermal reservoirs are then used to generate CO 2 , H 2 S, H 2 , N 2 , C.H. 4 Geothermal water naturally contains dissolved gases such as argon, argon, argon gas, and argon sulphur dioxide. These gases are by-products of geothermal energy production and are of magmatic origin. Geothermal steam can be separated from the brine (geothermal water) and used to generate electricity by power turbines. Following this process, the steam is condensed and re-injected into the geothermal reservoir together with the brine (geothermal water). However, only a fraction of the gases from the original portion of the hot mixture extracted from the geothermal reservoir recondenses with the steam, leaving the remaining so-called non-condensable gases (hereafter NCG or NCG mixture) as a gaseous by-product of thermal energy production. These gases are usually removed from the condenser by vacuum pumps or ejectors and discharged into the atmosphere. Thus, currently, most geothermal power plants, for example in Iceland, produce significant amounts of H 2 S and CO 2 Figure 1 shows the CO emitted by several geothermal plants in Iceland. 2 and H 2This indicates the amount of S. The amount of gas released depends on the size of the plant as well as the geology of the site.

[0003] Based on the above, CO from geothermal power plants 2 and H 2 It is easy to understand that the emission of S is one of the main environmental problems of geothermal energy utilization. 2 H is a so-called greenhouse gas that contributes to global warming, and hydrogen sulfide is a colorless, flammable, highly toxic gas with the characteristic odor of rotten eggs. 2 Exposure to S can cause health problems depending on the level and duration of exposure. Low-level, long-term exposure can cause eye inflammation and irritation, while short-term, high-level exposure can cause the same amount of H in the air. 2 Concentrations of S above 300 ppm can cause dizziness, headaches, nausea and even death.

[0004] H in geothermal fluids 2 The concentration of S is usually in the range of several ppb to several hundred ppm (Arnorsson, S. (1995a) Hydrothermal systems in Iceland: Structure and conceptual models. 1. High-temperature areas. Geothermics 24, 561-602, Arnorsson, S. (1995b) Hydrothermal systems in Iceland: Structure and conceptual models. 2. Low-temperature areas. Geothermics 24, 603-629). During utilization of high-temperature geothermal fluids, H 2 S is concentrated in the vapor phase and then released into the atmosphere after the vapor condenses. 2 S is released into the top of the cooling tower, where it is mixed with high concentrations of H 2 S is dispersed into the air to reduce the risk of it approaching power plants. 2 S is the CO contained in exhaust gas 2 , H 2 , N 2 , C.H. 4Along with other gases such as sulphur dioxide, sulphur dioxide, and toluene, these gases can be carried away from power plant sites by the wind and, under some weather conditions, can cause unpleasant odors in nearby communities.

[0005] H from exhaust 2 S and CO 2 Several methods have been implemented in the past in an attempt to dispose of gases such as H. 2 This involves separating S from other gases and subsequently oxidizing it. Another known method of disposing of these gases is by mixing the entire non-condensable gas stream with water. However, this requires very large amounts of water in many situations, since the solubilities of the various gases in the non-condensable gas stream are very different. For example, at 293 K (about 20 C) and 1 atm (about 1 bar), the relatively soluble CO 2 and H 2 The solubility of S is 0.169g and 0.385g per 100g of water, respectively, while H is relatively insoluble. 2 , N 2 , O 2 , Ar and CH 4 The solubilities of are only 0.00016, 0.0019, 0.0043, 0.0062, and 0.0023 g per 100 g of water, respectively.

[0006] U.S. Pat. No. 5,656,172 discloses a method for the extraction of H from geothermal non-condensable gases for the purpose of producing acidic brines (geothermal waters) that can be used to dissolve scale and other precipitates and / or inhibit further mineralization in the context of geothermal energy production. 2 SO 4 However, such brines (geothermal waters) do not themselves provide the H2O2-containing aqueous brines contemplated by the present invention. 2 S and CO 2 It is not useful for direct reinjection and storage of H 2 SO 4 is a strong acid, so H, which is a weak acid, 2Only a small amount of sulfur is needed to acidify the brine (geothermal water) compared to using S. Thus, a small portion of the sulfur emissions from a geothermal power plant can be removed before extensive measures are required to mitigate corrosion of the steel piping of the reinjection system and the casing of the reinjection wells.

[0007] US Patent No. 20020062735 describes a process for producing natural gas, i.e., mainly CH 4 The process described is for the pretreatment of natural gas for heating and cooking purposes, comprising: 2 S and CO 2 The purpose of the present invention is to pre-treat natural gas by purifying it from natural gas. Therefore, any of the methods or systems described in US20020062735 are intended to produce H2O, a by-product of geothermal energy production, rather than natural gas. 2 S and CO 2 H from NCG, etc., mentioned above, is much more abundant. 2 S and CO 2 Rich gas to H 2 S and CO 2 It does not address how to dispose of the above, nor does it provide a solution that would enable a method or system for such disposal.

[0008] US2011225971 describes a method for removing hydrogen sulfide from the steam condensate of a geothermal power unit by contacting it with the condenser exhaust gas of the same geothermal power unit containing carbon dioxide. The method described thus removes hydrogen sulfide from the NCG mixture. 2 H from the condensate instead of S 2 Regarding the removal of S, in any case, the H of the NCG mixture contemplated by the present invention 2 S and CO 2 It does not rely on absorption of the water into steam condensate or any other water stream.

[0009] US Patent No. 5,340,382 describes a method for absorbing acid gases (described as a mixture of carbon dioxide and hydrogen sulfide) from a hydrocarbon well into water. According to US Patent No. 5,340,382, the acid gases are absorbed into the water by the use of a static mixer, after which the mixture is pressurized to flow through a pipeline to an injection pump, through which it is returned to the waste layer. According to US Patent No. 5,340,382, the water containing the acid gases should be maintained at a pressure higher than the pressure at the outlet of the static mixer. It is clear from US Patent No. 5,340,382 that the method described therein is not suitable for the purpose of absorbing acid gases (described as a mixture of carbon dioxide and hydrogen sulfide) into the water, as in the context of the present invention. 2 and H 2 Both S and H 2 , N 2 , O 2 , Ar and CH 4 Compression of NCG mixtures that also contain at least one of 2 S and CO 2 It is quite clear that the method described in US Pat. No. 5,340,382 concerns the compression and absorption of a (sour) gas mixture consisting of only CO2. Thus, the method described in US Pat. No. 5,340,382 is directed to the compression and absorption of relatively soluble CO2 from an NCG mixture. 2 and H 2 It is not intended to selectively absorb the S gas into the liquid steam condensate (or any other water stream) and at the same time, to absorb the relatively insoluble H 2 , N 2 and C.H. 4 The gases are left in the NCG mixture as in the method of the present invention. Thus, the method of U.S. Pat. No. 5,340,382 does not include the H 2 S and CO 2 The present method assumes that H has already been separated from any other gases, but the method of the present invention is precisely that, i.e., H in the gas mixture. 2 S and CO 2from other gases present in the mixture. That the method described in US 5,340,382 does not contemplate any separation of gases in the NCG mixture is also very clear from the fact that after the so-called acid gases are mixed with water in a so-called static mixer, this mixture remains pressurized according to US 5,340,382 and is directly injected into the waste bed without removing the gas from the liquid (see column 3, 1.62-1.34). Thus, unlike the method of the present invention, the method of US 5,340,382 does not contemplate having both a gas stream and a water stream leaving the mixing unit (the so-called static mixer in US 5,340,382), but only one single stream containing both water and gas. This difference is also very clear from the fact that a static mixer is used instead of, for example, an absorption tower according to the teaching of US 5,340,382 (see column 2, 1.22-24), while on the other hand an absorption tower is the preferred process for carrying out the method according to the present invention.

[0010] No. 5,694,772 describes a method for disposing of hydrogen sulfide present in geothermal fluids used in geothermal power plants of the type that produce a gas stream containing hydrogen sulfide and a spent geothermal liquid stream, which comprises compressing both the spent geothermal liquid and the gas stream, and contacting them to produce a pressurized gas stream that is substantially free of hydrogen sulfide, and a liquid effluent. The method described relies on compression of the gas mixture before contacting it with a vapor condensate in a so-called packed tower, which reduces the H of the gaseous NCG mixture. 2 S and CO 2 It should be understood that the method contemplated in U.S. Pat. No. 5,694,772 is not dependent on the absorption of both hydrogen sulfide and carbon dioxide into the steam condensate, as is shown in both the figure (FIG. 1) and text (column 4, lines 53-56) of U.S. Pat. No. 5,694,772, which does not include any CO 2This is supported by the fact that H is still part of the compressed gas stream, which is then vented to the atmosphere. Thus, the solution described in U.S. Pat. No. 5,694,772 is apparently a means to reduce H from the NCG mixture. 2 S and CO 2 The aim is not to separate both H 2 The '772 patent also mentions that the process described therein can be optimized by adding chlorine to the so-called packed column mentioned above. The addition of chlorine can be understood to be specifically aimed at increasing the oxidation of hydrogen sulfide to other sulfur species that have a higher solubility in aqueous solutions. In contrast, simple absorption would not involve a change in the chemical species present in the system. The proposal to add chlorine in the context of the '772 patent also includes the idea that these are aimed at reducing the amount of CO2 that may be present in the gas mixture. 2 Instead, H 2 This clearly indicates that the purpose of the disposal is only for disposal of CO. In fact, the solubility of chlorine in water at 293 K (about 20 C) and 1 atm (about 1 bar) is about 0.7 g per 100 g of water. 2 (0.169 g per 100 g of water) and adding chlorine to the so-called packed towers mentioned above reduces CO 2 There is no similar oxidizing role for chlorine (as mentioned above for hydrogen sulfide) in the liquid stream in the first place (i.e. in a chlorine-free system). 2 would be expected to reduce the total absorption of

[0011] No. 4,244,190 describes a method for treating two-phase geothermal brine (geothermal water) produced from an underground geothermal reservoir containing hydrogen sulfide and non-condensable gases containing heavy and / or transition metals in solution, which involves converting hydrogen sulfide to higher oxidation states of sulfur and / or other sulfur compounds. Thus, the method described involves the conversion of hydrogen sulfide to higher oxidation states of sulfur and / or other sulfur compounds. 2 H by converting S to a higher oxidation state 2 Regarding the removal of S, in any case, the H 2 S and CO2 does not rely on absorption into the steam condensate or any other water stream as contemplated by the present invention.

[0012] WO 9322032 describes a method for treating gas containing ammonia and hydrogen sulfide components, which involves increasing the pH of an oxygenated liquid by adding ammonia or an ammonia precursor and contacting the gas in a mixing zone with a liquid of elevated pH under conditions sufficient to remove a significant portion of the hydrogen sulfide. The method described thus achieves the production of H2O from a gaseous mixture containing a significant amount of ammonia, rather than the typical composition of NCG from a geothermal reservoir. 2 In any case, the removal of S from the NCG mixture into the steam condensate or any other water stream contemplated by the present invention may be accomplished by removing H 2 S and CO 2 It does not depend on the absorption of

[0013] US Patent No. 5,085,782 describes a method for recovering and using non-condensable gases produced during flashing of geothermal brine (geothermal water), which gases contain large amounts of CO 2 and a small amount of H 2 S, which involves introducing said non-condensable gases into a condensate of steam derived from brine (geothermal water) in the presence of an oxidizing agent to oxidize substantially all of the hydrogen sulfide. Thus, the method described involves the introduction of H 2 By converting S to a higher oxidation state, H 2 Concerning removing S.

[0014] Therefore, the inventors of the present invention have prepared a method for extracting H from NCG for later storage. 2 S and CO 2 The relatively soluble CO from the NCG mixture can be extracted without resorting to the addition of chlorine to separate, capture and prepare CO or, for example, oxidize sulfur to a higher oxidation state. 2 and H 2It relies solely on the absorption of S gas into the liquid vapor condensate (or any other water stream) and at the same time the relatively poorly soluble H in the NCG mixture. 2 , N 2 and C.H. 4 For the first time, a system and method have been described that meets the need for an environmentally friendly method for the later use of leaving gas. Summary of the Invention

[0015] As mentioned above, hydrogen sulfide (H 2 S) and carbon dioxide (CO 2 ) is prepared by the use of H from a mixture of geothermal non-condensable gases (NCGs) and other gases. 2 , N 2 , C.H. 4 and / or Ar gas. 2 S) and carbon dioxide (CO 2 ) rich gas, H 2 S and CO 2 It would be advantageous to have an effective and environmentally friendly method for separating soluble gases such as H 2 S and CO 2 The present invention aims to mitigate, alleviate or eliminate one or more of the above mentioned disadvantages separately or in any combination. 2 S and CO 2 It can be seen as an object of the present invention to provide a method for solving the above-mentioned or other problems of the prior art related to

[0016] To better address one or more of these concerns, in a first aspect of the present invention, NCG et al. 2 , N 2 , C.H. 4 and / or Ar gas. 2 S and CO 2 Rich gas mixture (G1) to H 2 S and CO 2 A method for capturing soluble gases is provided, comprising at least the following: · NCG, etc., H 2 , N 2 , C.H.4 and / or Ar gas. 2 S and CO 2 Pressurizing the rich gas mixture (G1) to a pressure of 3 to 20 bar, for example 3 to 15 bar; H 2 S and CO 2 And H 2 , N 2 , C.H. 4 and / or Ar, contacting said pressurized gas mixture (G1) stream with a water stream (W2); H 2 S and CO 2 And H 2 , N 2 , C.H. 4 and / or Ar from the pressurized gas mixture (G1). 2 S and CO 2 by absorption of at least a portion of the water flow (W2) The amount of dissolved H equivalent to that of the water flow (W2) 2 S and CO 2 The water stream (W4) enriched with H 2 S and CO 2 And H 2 , N 2 , C.H. 4 and / or Ar, compared to the gas mixture (G1) which also contains at least one of 2 S and CO 2 a pressurized gas flow (G3) depleted of Dissolved H 2 S and CO 2 The water stream (W4) enriched with an injection well for injecting said water flow (W4) into a geological reservoir, or injecting a water stream (W5) into a geological reservoir and transferring said water stream (W4) to one of the systems for using said water stream (W4) to assist in adjusting the pH of said water stream (W5); Includes.

[0017] In the context of the present invention, the term "transport" is understood as any means of transporting a liquid, for example water, or a gas (for example a gas mixture) from one place to another, for example by pumping.

[0018] In the context of the present invention, the term "flow" is understood as a substance, e.g. water or gas, moving in a given direction at a given velocity with a specific flow rate, which can be provided as either a volumetric flow rate or a mass flow rate. Volumetric flow rate is the volume of a fluid or gas passing a given point per unit time and is usually represented by the symbol Q (sometimes V). The SI unit of volumetric flow rate is m 3 / s. Thus, volumetric flow rate is equal to volume / time. Mass flow rate, on the other hand, is the mass of a fluid or gas passing a given point per unit of time. The SI unit of mass flow rate is kg / s.

[0019] In the context of the present invention, the term "water source or water" is understood as any kind of water, such as groundwater, ocean / sea water, spring water, geothermal condensate or brine (geothermal water), or surface water from a river, stream or lake.

[0020] In the context of the present invention, the term "injection well" is understood as any kind of structure that offers the possibility of depositing fluids or gases deep underground or just below the surface of the earth, such as devices for depositing fluids in rock formations such as basalt or basaltic rocks, and porous rock formations such as sandstone or limestone, or in or below shallow soil layers.

[0021] In the context of the present invention, CO 2 and / or H 2 The S-rich gas mixture is 2 and / or H 2 The relative content of S in the atmosphere is 2 and / or H 2 It is understood as any gas mixture with a relative content of S higher than

[0022] In the context of the present invention, the term "hydraulic pressure" is understood as the pressure exerted by hydraulic fluid in all directions in a vessel, well, hose, or whatever it is in. Hydraulic pressure can cause flow in a hydraulic system as fluid flows from higher pressure to lower pressure.

[0023] Pressure is measured in SI units, the pascal (Pa), or 1 Newton per square metre (1N / m 2 ) or 1kg / (m s 2 ) or 1 J / m 3 It is measured in psi (pounds per square inch), or more precisely pounds per square inch (pounds per square inch). Other commonly used pressure units are pounds per square inch (abbreviated psi) and bar. In SI units, 1 psi is equal to approximately 6895 Pa and 1 bar is equal to 100,000 Pa.

[0024] In the context of the present invention, (CO 2 and / or H 2 The term "partial pressure" of a gas (S) or simply "pressure" is understood as the conceptual pressure of a given gas in a mixture of gases if that gas itself occupied the entire volume of the original mixture at the same temperature. The total pressure of an ideal gas mixture is the sum of the partial pressures of the individual constituent gases in the mixture.

[0025] In the context of the present invention, the terms "pressurizing" and "pressurized" are understood as the process of bringing about and maintaining, respectively, a pressure higher than the surrounding pressure, for example a pressure higher than atmospheric pressure, for example between 3 and 20 bar, for example between 3 and 15 bar, for example between 4 and 10 bar, for example between 6 and 8 bar, for example 7 bar. In particular, the terms "pressurizing" and "pressurized" should not be taken in the context of the present invention to mean compressing a given gas or a given gas mixture to its liquid state, but rather to subject it, at a given temperature for a given gas or a given gas mixture, to a pressure above a certain threshold value.

[0026] In the context of the present invention, the term "contacting", e.g. contacting a gas stream with a water stream, is understood as bringing something into contact with something else, i.e. causing two or more things to touch each other, physically interact with each other, or associate with each other.

[0027] In the context of the present invention, the term "absorption", for example the absorption of a gas into water, is understood as a physical or chemical phenomenon or process in which atoms, molecules or ions enter a bulk phase, for example a liquid or solid material. An example of this is gas-liquid absorption (also known as scrubbing), which is an operation in which a gas mixture is brought into contact with a liquid with the purpose of preferentially dissolving one or more components of the gas mixture and providing their solution in the liquid. In principle, there are two types of absorption processes: physical absorption and chemical absorption, depending on whether there is a chemical reaction between the solute and the solvent (absorbent). In processes in which water is used as the absorbent, such as in one of the processes of the present invention, very little chemical reaction occurs between the absorbent and the solute, and therefore the process is generally called physical absorption. However, in processes in which the pH of the absorbent is adjusted by the addition of a base or acid, the absorption into water may be accompanied by a rapid and irreversible neutralization reaction in the liquid phase, depending on the chemical nature of the solute, and then the process may be called chemical absorption or reactive absorption. Thus, chemical reactions induced, for example, by pH adjustment, can be used to increase the rate of absorption, increase the absorption capacity of a solvent, increase the selectivity to preferentially dissolve only certain components of a gas mixture, and / or convert harmful components of a gas mixture into safe or safer compounds.

[0028] In the context of the present invention, the term "generate", e.g., generating a water flow or a pressurized gas flow, is understood as causing, causing, producing, bringing about or obtaining something, e.g., a water flow or a pressurized gas flow.

[0029] In the context of the present invention, "injection / reinjection" or "inject / reinject" is understood as the forcible introduction / reintroduction of something into something else, for example to force a fluid into a subterranean formation.

[0030] In the context of the present invention, the term "geological reservoir" is understood as a subterranean structure, e.g. a fracture in basaltic rock, which expands in a direction other than upwards and downwards, and which provides a flow path for the water injected into the injection well according to the present invention, and which may include what is called a geothermal reservoir. In the present context, the term "geothermal reservoir" is understood as a fracture in hot rock which expands in a direction other than upwards and downwards, and which provides a flow path for the water injected from the well.

[0031] Therefore, dissolved H 2 S and CO 2 For example, by generating a water stream (W4) enriched with CO from the remaining gases of the NCG 2 and H 2 Methods are provided for separating S and thus preparing these gases for later disposal or for use, for example, in adjusting the pH of a fluid. Disposal can be performed, for example, by removing dissolved CO 2 and H 2 It may be based on injecting the S-enriched water stream (W4) back into the geothermal reservoir, where it forms chemical bonds via water-rock reactions. Thus, the water-rock reactions already taking place in natural geothermal systems can be used to enrich dissolved H 2 S and CO 2 The CO enriched water stream (W4) can be utilized by injecting it back into the geothermal system. 2 and H 2 CO is produced by dissolving S in the water stream and returning it to its original location. 2 and H 2 Separating S should be seen as an ideal way to reduce gas emissions from geothermal power plants, for example.

[0032] In one embodiment, the H 2 S and CO 2 Rich gases are the following gases: H 2 , N 2 , C.H. 4 and / or Ar, 2 S and CO 2H from the remaining gas in the rich gas 2 S and CO 2 The method for removing the gas is 2 , N 2 , C.H. 4 , and / or Ar gas. 2 S and CO 2 Rich gas, H 2 S and CO 2 is contacted with water to produce dissolved H 2 S and CO 2 The remaining refractory H 2 , N 2 , C.H. 4 , and / or through an absorption tower to separate the H from the remaining refractory gases. 2 S and CO 2 A simple method for isolating

[0033] In a second aspect of the present invention, a method for producing a geothermal gas, such as a geothermal non-condensable gas (NCG), is provided. 2 , N 2 , C.H. 4 and / or Ar gas. 2 S) and carbon dioxide (CO 2 ) rich gas mixture (G1) to H 2 S and CO 2 A system for separating soluble gases is provided, comprising at least: H 2 S and CO 2 And H 2 , N 2 , C.H. 4 and / or Ar, to a pressure of 3 to 20 bar, for example 3 to 15 bar, H 2 S and CO 2 And H 2 , N 2 , C.H. 4 and / or Ar, with a water flow (W2); H2 S and CO 2 And H 2 , N 2 , C.H. 4 and / or Ar from the pressurized gas mixture (G1). 2 S and CO 2 The absorption of at least a portion of the water into the water flow (W2) produces a dissolved H equivalent to that of the water flow (W2). 2 S and CO 2 The water stream (W4) enriched with H 2 S and CO 2 And H 2 , N 2 , C.H. 4 and / or Ar, compared to the gas mixture (G1) which also contains at least one of 2 S and CO 2 a pressurized gas flow (G3) depleted of Dissolved H 2 S and CO 2 The water stream (W4) enriched with an injection well for injecting said water flow (W4) into a geological reservoir, or a means for injecting the water stream (W5) into a geological reservoir and transferring the water stream (W4) to one of the systems for using the water stream (W4) to assist in adjusting the pH of the water stream (W5); Includes.

[0034] In a particular preferred embodiment of the system according to the invention, H 2 S and CO 2 And H 2 , N 2 , C.H. 4 and / or Ar from the pressurized gas mixture (G1). 2 S and CO 2 into said water stream (W2), said means comprising one or more absorber towers.

[0035] It should be noted that the term "water" according to the present invention may mean fresh water, water from geothermal wells, brine (geothermal water), sea water, etc. Thus, the water source may be any type of water. Similarly, CO 2 and / or H 2 The S gas may come from any source, such as conventional power plants, geothermal power plants, industrial production, gas separation stations, etc.

[0036] In general, the various aspects of the invention can be combined and integrated in any manner possible within the scope of the invention. These and other aspects, features and / or advantages of the invention will be apparent from and elucidated with reference to the embodiments described hereinafter.

[0037] A number of embodiments of the present invention will now be described, by way of example only, with reference to the drawings in which: [Brief description of the drawings]

[0038] [Figure 1] FIG. 1 shows the amount of CO2 and H2S emitted by various geothermal power plants in Iceland. [Diagram 2] 1 is a flow chart illustrating a method according to the present invention for separating soluble gases including hydrogen sulfide (H2S) and carbon dioxide (CO2) from a H2S and CO2 rich gas mixture, such as NCG, that also includes at least one of H2, N2, CH4 and / or Ar gases. [Diagram 3] FIG. 1 illustrates a system according to the present invention for separating soluble gases including hydrogen sulfide (H2S) and carbon dioxide (CO2) from a H2S and CO2 rich gas mixture, such as NCG, that also includes at least one of H2, N2, CH4 and / or Ar gases. [Figure 4] FIG. 2 illustrates an absorber tower and a reinjection well in accordance with the system and method of the present invention. [Diagram 5] FIG. 1 shows a method according to the present invention where CO2 / H2S is removed (in an absorption tower at 5-6 bar) and then used for either (1a) re-injection as an aid in pH adjustment, or (1b) re-injection into a geological reservoir. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0039] Figure 2 shows the hydrogen sulfide (H 2 S) and carbon dioxide (CO 2 ) is dissolved in water, such as geothermal non-condensable gas (NCG), 2 , N 2 , C.H. 4 and / or Ar gas. 2 S and CO 2 FIG. 1 shows a flow chart of the method according to the invention for separating from a rich gas mixture. 2 S and CO 2 It should be noted that the rich gas mixture should not be construed as being limited to NCG. However, for simplicity, in the following, H 2 S and CO 2 The rich gas mixture is assumed to be NCG, which is H 2 , N 2 , Ar and CH 4 The gas may further include, but is not limited to, one or more gases selected from:

[0040] In step (S1) 201, H is extracted from the remaining gas contained in NCG. 2 S and CO 2 As will be discussed in more detail in relation to FIG. 2 S and CO 2 dissolves in a liquid, typically water, thus freeing the remaining less soluble H 2 , N 2 , C.H. 4 This is done by directing the NCG through an absorption tower where it is separated from the H and Ar gases. The dissolved H 2 S and CO 2 The resulting water stream containing the nitrate may be directed to, for example, a reinjection well for disposal / storage, or to another process for pH adjustment.

[0041] Referring to FIG. 3, the present invention relates to a process for the production of hydrogen sulfide (H 2 S) and carbon dioxide (CO 2) and H 2 , N 2 , C.H. 4 and / or Ar, 2 S and CO 2 Regarding a method for removing H 2 S and CO 2 And H 2 , N 2 , C.H. 4 and / or Ar; H 2 S and CO 2 And H 2 , N 2 , C.H. 4 and / or Ar, contacting said pressurized gas mixture (G1) stream with a water stream (W2); H 2 S and CO 2 And H 2 , N 2 , C.H. 4 and / or Ar from the pressurized gas mixture (G1). 2 S and CO 2 by absorption of at least a portion of the water flow (W2) The amount of dissolved H equivalent to that of the water flow (W2) 2 S and CO 2 The water stream (W4) enriched with H 2 S and CO 2 And H 2 , N 2 , C.H. 4 and / or Ar, compared to the gas mixture (G1) which also contains at least one of 2 S and CO 2 a pressurized gas stream (G3) depleted of Dissolved H 2 S and CO 2 The water stream (W4) enriched with an injection well for injecting said water flow (W4) into a geological reservoir, or - injecting the water stream (W5) into a geological reservoir and transferring it to one of the systems for using the water stream (W4) to help adjust the pH of the water stream (W5); Includes.

[0042] Dissolved H 2 S and CO 2 an injection well for injecting said water stream (W4) enriched by the method into a geological reservoir; or Not shown in FIG. 3 are the steps of injecting water stream (W5) into the geological reservoir and transferring water stream (W4) to any of the systems for using water stream (W4) to assist in adjusting the pH of water stream (W5).

[0043] Dissolved H 2 S and CO 2 The process of transporting the water stream (W4) enriched with HF to an injection well for injecting the water stream (W4) into a geological reservoir is shown in Figure 4. In the particular embodiment shown in Figure 4, the water stream (W4) is co-injected with another water stream labeled "geothermal water".

[0044] The use of water stream (W4) for pH adjustment of water stream (W5) is not shown in Figures 3 or 4, but is shown for example in Figure 5, where part of water stream (W4) is used for reinjection (1b) and part is used for pH adjustment (1a) of water stream (W5), which is shown as "geothermal water".

[0045] In a particularly preferred embodiment of the method according to the invention, H 2 S and CO 2 And H 2 , N 2 , C.H. 4 and / or Ar, the pressure of the pressurized gas mixture (G1) is from 3 to 20 bar, such as from 3 to 15 bar, or from 4 to 20 bar, such as from 4 to 14 bar, for example from 5 to 13 bar, such as from 6 to 12 bar, for example from 7 to 11 bar, such as 7, 8, 9, 10 and 11 bar.

[0046] In a further particularly preferred embodiment of the process according to the invention the temperature of said gas stream (G1) is between 30 and 50°C, such as between 32 and 48°C, for example between 33 and 47°C, such as between 34 and 46, for example between 35 and 45, such as between 36 and 44, for example between 37 and 43, such as between 38 and 42, for example between 39, 40 and 41°C.

[0047] In a further particularly preferred embodiment of the process according to the invention, the temperature of the water stream (W2) is between 4 and 40°C, such as between 6 and 35°C, for example between 8 and 30°C, such as between 10 and 25°C, for example between 11 and 24°C, such as between 12 and 23°C, for example between 13 and 22°C, such as between 14 and 21°C, for example between 15 and 20°C, for example 15, 16, 17, 18, 19 and 20°C.

[0048] In a further particularly preferred embodiment of the process according to the invention, the pressure of the water stream (W2) is between 6 and 23 bar, such as between 6 and 22 bar, for example between 6 and 21 bar, such as between 6 and 20 bar, for example between 6 and 19 bar, such as between 6 and 18 bar, for example between 7 and 17 bar, such as between 8 and 16 bar, for example between 9 and 15 bar, such as between 10 and 14 bar, for example between 9, 10, 11, 12, 13 and 14 bar. 2 S and CO 2 And H 2 , N 2 , C.H. 4 and / or Ar, for example, about 2 to 5 bar higher than the pressure of the pressurized gas mixture (G1) 2 S and CO 2 And H 2 , N 2 , C.H. 4 and / or Ar. 2 S and CO 2 And H 2 , N 2 , C.H. 4If the pressure of the pressurized gas mixture (G1), which also contains at least one of H and / or Ar, is about 6 bar, the pressure of the water stream (W2) should preferably be about 9 bar. Nevertheless, those skilled in the art will understand that 2 S and CO 2 And H 2 , N 2 , C.H. 4 It will be appreciated that the optimal pressure difference between the pressure of the pressurized gas mixture (G1), which also includes at least one of Ar and / or Ar, and the water stream (W2) will depend, for example, on the applicable absorption tower height and the applicable water distribution system pressure drop, as well as on where in a given system the pressure is measured.

[0049] In a further particularly preferred embodiment of the process according to the invention the flow rate of the gas mixture (G1) is between 0.2 and 1.5 kg / s, such as between 0.25 kg / s and 1.45 kg / s, for example between 0.3 and 1.4 kg / s, such as between 0.35 and 1.35 kg / s, for example between 0.4 and 1.3, such as between 0.45 and 1.25 kg / s, for example between 0.5 and 1.2 kg / s, such as between 0.55 and 1.15 kg / s, for example between 0.6 and 1.1 kg / s, for example between 0.65 and 1.05 kg / s, for example between 0.7 and 1 kg / s, for example 0.7, 0.75, 0.8, 0.85, 0.9, 0.95 and 1 kg / s.

[0050] In a further particularly preferred embodiment of the method according to the invention the flow rate of said water stream (W2) is 36-56 kg / s, such as 37-55 kg / s, for example 38-54 kg / s, such as 39-55 kg / s, for example 40-53 kg / s, such as 41-52 kg / s, for example 42-51 kg / s, such as 42, 43, 44, 45, 46, 47, 48, 49 and 50 kg / s.

[0051] In a further particularly preferred embodiment of the method according to the invention, the gas mixture (G1) is a geothermal non-condensable gas mixture (NCG).

[0052] Also, apart from the above method, the present invention also relates to a process for the production of hydrogen sulfide (H 2S) and carbon dioxide (CO 2 ) and H 2 , N 2 , C.H. 4 and / or Ar, 2 S and CO 2 A system for removing at least the following: H 2 S and CO 2 And H 2 , N 2 , C.H. 4 and / or Ar; and H 2 S and CO 2 And H 2 , N 2 , C.H. 4 and / or Ar, with a water flow (W2); H 2 S and CO 2 And H 2 , N 2 , C.H. 4 and / or Ar from the pressurized gas mixture (G1). 2 S and CO 2 The absorption of at least a portion of the water into the water flow (W2) produces a dissolved H equivalent to that of the water flow (W2). 2 S and CO 2 The water stream (W4) enriched with H 2 S and CO 2 And H 2 , N 2 , C.H. 4 and / or Ar, compared to the gas mixture (G1) which also contains at least one of 2 S and CO 2 a pressurized gas flow (G3) depleted of Dissolved H 2 S and CO 2 The water stream (W4) enriched with an injection well for injecting said water flow (W4) into a geological reservoir, or a means for injecting the water stream (W5) into a geological reservoir and transferring the water stream (W4) to one of the systems for using the water stream (W4) to assist in adjusting the pH of the water stream (W5); Includes.

[0053] In a particular preferred system according to the invention, H 2 S and CO 2 And H 2 , N 2 , C.H. 4 and / or Ar, with a water stream (W2), H 2 S and CO 2 And H 2 , N 2 , C.H. 4 and / or Ar from the pressurized gas mixture (G1). 2 S and CO 2 The absorption of at least a portion of the water into the water flow (W2) produces a dissolved H equivalent to that of the water flow (W2). 2 S and CO 2 The water stream (W4) enriched with H 2 S and CO 2 And H 2 , N 2 , C.H. 4 and / or Ar, compared to the gas mixture (G1) which also contains at least one of 2 S and CO 2 a pressurized gas flow (G3) depleted of is an absorption tower.

[0054] While the present invention has been illustrated and described in detail in the drawings and the foregoing description, such illustration and description are considered to be illustrative or exemplary and not restrictive, and the present 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. 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 measures cannot be used to advantage. Any reference signs in the claims should not be construed as limiting the scope. EXAMPLES

[0055] [Example 1] CO 2 / H 2 The experimental injection of S was carried out at the Hellisheiði power plant on the central Hengill volcano, located in southeast Iceland in the Western Volcanic Zone, approximately 20 km southeast of Reykjavik. Currently, there are two producing geothermal fields in the Hengill area, Nesjavellir in the north and Hellisheiði in the south of the region.

[0056] Sixty-three production wells have been drilled in the Hengill-Hellisheidi geothermal field, providing valuable information on its stratigraphy and alteration zones.As reported in the scientific literature by Franzson et al., Franzson, H., Kristjansson, B. R., Gunnarsson, G., Bjornsson, G., Hjartarson, A., Steingrimsson, B., Gunnlaugsson, E. and Gislason, G. (2005) The Hengill-Hellisheidi Geothermal field. Development of a Conceptual Model. Proceedings World Geothermal Congress 2005, and incorporated herein by reference in its entirety, the subsurface basalt formation in the Hengill area primarily comprises a hyaloclastite volcanic layer at a depth of approximately 1000 m below sea level, with a more pronounced lava sequence underlying it. As reported in the scientific literature by Helgadottir et al., Helgadottir, HM, Snaebjornsdottir, SO, Nielsson, S., Gunnarsdottir, SH, Matthiasdottir, T., Hardarson, BS, Gunnlaugur M. Einarsson, GM and Franzson, H. (2010) Geology and Hydrothermal Alteration in the Reservoir of the Hellisheidi High Temperature System, SW-Iceland. Proceedings, World Geothermal Congress 2010, which is incorporated herein by reference in its entirety, hydrothermal alteration ranges from fresh rocks in the overlying cold groundwater system, through zeolite assemblages, to high temperature mineral assemblages including epidote, wollastonite and actinolite.

[0057] Geothermal gas from the Hetlissheidge geothermal field is mainly CO 2 , H 2 S, H 2 , and to a lesser extent N 2 , C.H. 4A pilot gas separation station was built next to the Hetlissheidi power plant. The pilot station separates geothermal gas coming from the power plant condenser into CO, Ar and H2O. 2 and H 2 S-rich gas stream(s) and other gases (mainly H 2 , N 2 , Ar, O 2 and / or CH 4 ) and a gas stream containing CO 2 and H 2 The oxygen in the gas stream separated from S comes from atmospheric contamination of the geothermal gases. About 3% of the total geothermal gas coming from the power plant is separated in this way. 2 / H 2 S gas stream(s) is CO 2 / H 2 S injection, but the remaining gas was released into the atmosphere together with the remaining geothermal gas coming from the condenser of the Hetlissheidge power plant.

[0058] CO 2 / H 2 The S gas stream(s) were dissolved in groundwater along with a potassium iodide tracer close to the injection site and subsequently injected back into the geothermal reservoir. The objective of this project was to extract H from solution. 2 In order to remove S and store it in minerals in the geothermal reservoir, 2 The control parameters were the same as those controlling the concentration of S.

[0059] The site selected for the experimental injection of hydrogen sulfide and carbon dioxide is at Sleggjubeinsdalur, approximately 2 km northeast of the Hellisheiði power plant. This is due to favorable reservoir temperatures, the power plant and therefore the H 2 It was selected based on its proximity to the S source, tracer testing, and the fact that the site had a high-temperature liquid enthalpy well available for injection experiments. 2 S gas was transported from the pilot gas separation station, dissolved in geothermal water near the injection site, and then injected into well HE-08.

[0060] HE-08 is a 2808 m deep vertical well that was drilled in 2003 for production purposes but was found to be unusable as a production well. Well HE-08 was selected for injection because a clear connection between this well and HE-08 was observed during the drilling of a nearby well. The connection between the wells was further investigated with tracer tests described below.

[0061] The stratigraphy and changes of the Hengill-Hellisheidi geothermal field and injection site are described in Franzon et al.,Franzson,H.,Kristjansson,BR,Gunnarsson,G.,Bjornsson,G.,Hjartarson,A.,Steingrimsson,B.,Gunnlaugsson,E.and Gislason,G.(2005)The Hengill-Hellisheidi Geothermal field.Development of a Conceptual Model.Proceedings Worls Geothermal Congress 2005, and in the scientific literature by Helgadottir et al.,Helgadottir,HM,Snaebjornsdottir,SO,Nielsson,S.,Gunnarsdottir,SH,Matthiasdottir,T.,Hardarson,BS,Gunnlaugur M.Einarsson,GMand Franzson,H.(2010)Geology and Hydrothermal Alteration in the Reservoir of the Hellisheidi High Temperature System, SW-Iceland. Proceedings, World Geothermal Congress 2010, which are incorporated herein by reference in their entirety. The main rock formations at the injection sites are subglacially formed hyaloclastites with occasional lava series. The lava series is prominent below about 1400 m below sea level. The aquifer temperatures at the injection sites are 260°C-270°C, as indicated by application of quartz geothermometers and calculated formation temperatures of the discharged fluids. The prominent aquifer in HE-08 is at a depth of 1350 m, with formation temperatures of about 270°C, which is in close agreement with the quartz geothermometers. The rock formations at the injection sites go through all typical alteration zones of the high temperature region, from fresh rock to the epidote-amphibole zone.

[0062] During drilling of HE-08, a pressure relationship was observed between HE-08 and KhG-1, a nearby well used for water level measurements. During drilling of HE-31, HE-46, and HE-52, a pressure relationship was also observed between the drilled wells and wells HE-8 and KhG-1. Tracer tests were performed to confirm the presence of H to nearby wells. 2 The possible flow paths of S-rich geothermal brines were identified and quantified, and the results were used to organize a potential monitoring well monitoring program.

[0063] 250 kg of sodium benzoate (NaC 6 H 5 CO 2 Tracer tests were conducted by dissolving 1,000 liters of water and subsequently injecting it into well HE-8. After injection of the tracer geothermal brine, it was pumped into the well for 56 days at a volumetric flow rate of 4 l / s. At the time of the tests, the wells adjacent to the injection well were drained. The wells were HE-5, HE-31, HE-46 and HE-52. Periodically samples were collected from their weirboxes or using web receptacles and analyzed for benzoate ions using ion chromatography. Benzoate concentrations were below the detection limit in all samples from wells HE-52, HE-5 and HE-31. Elevated levels of benzoate concentration were only evident in well HE-46. Modeling of the tracer tests revealed that nearly 40% of the injected water was drained into well HE-46, taking into account the reported 20% decomposition of benzoate in 2 weeks at 270°C. The remaining benzoate was not considered. Benzoate injected into HE-08 began to appear in HE-46 after only two days, revealing a fast flow path between the two wells. Quartz geothermometers indicate that the aquifer temperature was 266°C, close to the aquifer temperature in HE-08 and all wells near the injection site.

[0064] Hydrogen sulfide concentrations in the aquifer fluids of the Hellisheidi geothermal field have been studied extensively both as part of this injection project and as part of general geochemical monitoring of the wells and have been reported in the scientific literature by Stefansson et al. and Scott et al., Stefansson, A., Arnorsson, S., Gunnarsson, I., Kaasalainen, H. and Gunnlaugsson, E. (2011). The geochemistry and sequestration of H2S into hydrothermal system at Hellisheidi, Iceland. J. Volcanol. Geoth. Res. 202, 179-188); Scott S., Gunnarsson, I., Stefansson, A. and Gunnlaugsson, E. (2011). Gas Chemistry of the Hellisheidi Geothermal Field, SW-Iceland. Proceedings 36th Stanford Geothermal Workshop, which are incorporated herein by reference in their entirety. Calculated H in high-temperature aquifer fluids 2 S concentrations range from 15 to 264 ppm. Concentrations increase with increasing temperature and appear to be controlled by the mineral buffer assemblage. The majority of data points are close to the equilibrium lines of pyrite, pyrrhotite, prehnite and epidote or pyrite, pyrrhotite and magnetite mineral buffers. Stefansson et al. suggested that H is a stoichiometric parameter because geothermal areas in Iceland are typically low in magnetite, suggesting that this is unstable in the Icelandic geothermal system. 2 It is concluded that the S concentration is in equilibrium with the prehnite-bearing mineral assemblage.

[0065] H of the present invention 2 The S removal method is H 2 S Depends on the rate of chemical reactions that need to take place for mineralization to be successful. 2 S requires metals to form secondary minerals that are permanently stored in geothermal reservoirs. Reaction pathway modeling shows that H 2The main factors influencing the potential for S mineralization are discussed in Stefansson et al., Stefansson, A., Arnorsson, S., Gunnarsson, I., Kaasalainen, H. and Gunnlaugsson, E. (2011). The geochemistry and sequestration of H 2 S into hydrothermal system at Hellisheidi, Iceland. J. Volcanol. Geoth. Res. 202, 179-188. Above 250 °C, the rate of pyrite mineralization decreases during the formation of epidote, and as a result, H 2 More basaltic rock needs to be dissolved to mineralize S. Then, H 2 The optimum temperature for S sequestration is below the epidote stability zone, or about 230 °C (see Stefansson et al.). The rock formation temperature at the injection site is 260-270 °C. Dissolved H 2 The injected geothermal water containing S was heated from 100°C up to over 260°C before entering the monitoring well (HE-46), and H 2 It provides a wide temperature interval for mineralizing S.

[0066] Tracer tests at the injection sites revealed direct and fast flow paths from the injection and monitoring wells. The main aquifer spacing is approximately 450 m. This indicates that the main flow paths between the wells pass through fractures in the reservoir, as would be expected in a highly fractured geothermal reservoir such as the Hetlissheidge geothermal field. For experimental injection to be successful, it was necessary to remove the H from the aquifer, as sulfide minerals could fill the aquifer in the vicinity of the injection well and make it unavailable for injection. 2 The rate of S mineralization must not be too fast. Such a situation would require measures to slow down the mineralization reaction. These measures could be, for example, the reduction of H in the injected brine (geothermal water). 2This may be due to the fact that the concentration of S is reduced and therefore the supersaturation of the brine (geothermal water) with respect to the deposited sulfide minerals. On the other hand, when the brine (geothermal water) flows from the injection well to the monitoring well, the H is required for mineralization to occur. 2 The rate of S mineralization may be too slow. The response to this is to shut down the monitoring wells for a period of time, but 2 One option is to continue injecting S, which will increase the retention time in the geothermal reservoir and reduce H 2 S Allowing more time for isolation.

[0067] [Example 2] At the Hellisheiði geothermal power plant in Iceland, non-condensable geothermal gas (NCG) is produced by mixing three main gases: carbon dioxide (CO 2 ), hydrogen sulfide (H 2 S) and hydrogen (H 2 ) consists of nitrogen (N 2 ), methane (CH 4 Other gases such as argon (Ar) and argon (C) are also part of the NCG gases, but in very small proportions (see: http: / / www.thinkgeoenergy.com / treating-non-condensable-gases-ncg-of-geothermal-plants-experience-by-mannvit / ).

[0068] The non-condensable gas fraction resulting from the condensation process applied to the steam from the geothermal field is led to an absorption tower, where NCG (mainly CO 2 , H 2 S) is dissolved in water under high pressure (6-10 bar) at constant temperature (15°C-25°C).

[0069] Hydrogen sulfide (H 2 S) and carbon dioxide (CO 2 ) containing water-soluble gases H 2 S and CO 2 The operating conditions for capture from rich geothermal non-condensable gas mixtures (NCG) are outlined below. [Table 1]

[0070] Up to 98% of hydrogen sulfide and about 50% of carbon dioxide are dissolved in water, and H 2 S and CO 2 The gas was then reinjected deep into the rock at the plant site where it had mineralized (see: http: / / www.thinkgeoenergy.com / treating-non-condensable-gases-ncg-of-geothermal-plants-experience-by-mannvit / ).

[0071] Those skilled in the art will readily appreciate that the temperatures, flow rates and pressures described above are based on the specific conditions of the Hellisheiði geothermal power plant in Iceland, and may vary given other conditions of gas flow and temperature. Similarly, those skilled in the art will readily appreciate that the associated water flow should be a specific percentage of the actual gas flow, which should be modified depending on the applicable pressure and temperature.

[0072] [Example 3] This set of experiments was also carried out at the geothermal power plant in Hellisheiði, Iceland.

[0073] The subsurface rocks at the injection site are relatively permeable with porosity estimated at 8-10%, and consist of olivine tholeiitic basalt characterized by high permeability fractures at depths of less than 800 m. Temperatures in the target sour gas reservoir at depths of approximately 2000 m range from 220 to 260 °C.

[0074] CO 2 and H 2 S was dissolved in water and the mixture was released at a depth of 750 m. 2 / H 2 S / H 2 The O mixture was transported from the release site via an injection well extending to 1900-2200 m and discharged into the subsurface rocks. This combined fluid was then pumped up a hydraulic gradient into monitoring wells located 0.9-1.5 km from the injection well at a depth of 1900-2200 m.

[0075] A total of 4,526 tons of CO in one year 2 and 2,536 tons of H 2 S was injected. The end result of the injected gas mixture was monitored by periodic sampling of three monitoring wells located 984 m, 1356 m, and 1482 m downstream of the injection well at depths in the main aquifer, approximately 1900-2200 m deep. At these depths, the reservoir fluid is a single-phase aqueous fluid with a temperature of 266-277 °C because the hydraulic pressure is greater than the liquid-vapor saturation pressure of water. As the fluid rises up the monitoring wells, it boils as the pressure decreases. As a result, steam and water are sampled separately at 5.7-9.3 bar at the top of each monitoring well. Dissolved inorganic carbon (DIC) and hydrogen sulfide (H) in the gas phase were measured as described in Arnorsson et al. (2006) Geofluids 6, 203-216. 2 S) and CO 2 and H 2 Samples were collected and analyzed to determine S.

[0076] The percentage of injected gas mineralization was calculated by comparing measured aqueous DIC and dissolved sulfur (DS) concentrations in sampled monitoring wells with those assuming only mixing and dilution and no reaction occurring below the surface.

[0077] The difference between the calculated and measured DIC and DS is the 2 More than 50% of the injected H 2 It was shown that 76% of S was mineralized.

[0078] [Example 4] This set of experiments was also carried out at the geothermal power plant in Hellisheiði, Iceland. The system was operated under the conditions described in Example 2.

[0079] Dissolved CO at flow rates of 0.9–1.4 l / s for 153 days 2 (4095-6388mg / l) and H 2Water containing S (1933-3811) was used in a pH-adjusted geothermal brine stream at 18-20 l / s. 2 and H 2 The concentrations of S were 254-448 mg / l and 170-305 mg / l, respectively, and the pH was 5.5-6.7. A mixture with a temperature of 117 °C was transferred through a heat exchanger and cooled to 60 °C, the pressure drop across the exchanger was monitored, and the amount of scaling was estimated by weighing the heat exchanger before and after the experiment. No pressure drop was observed across the heat exchanger, and the measured scaling was 2 μg / l. For comparison, untreated geothermal brine was transferred through the heat exchanger at the same flow rate and temperature drop for 53 days. The experiment could not be extended further because the heat exchanger clogged with a measured scaling of 111 μg / l.

Claims

1. Hydrogen sulfide (H ２ S) and carbon dioxide (CO ２ ) and H ２ , N ２ , C.H. ４ and / or Ar from a non-condensable gas (NCG) mixture (G1) ２ At least a portion of S and CO ２ 1. A method for removing at least 50% of H ２ S and CO ２ And H ２ , N ２ , C.H. ４ and / or Ar, to a pressure of 6 to 20 bar; H ２ S and CO ２ And H ２ , N ２ , C.H. ４ and / or Ar, with a water flow (W2), the pressure of which is between 6 and 23 bar and the flow rate (kg / s) of which is between 36 / 1.5 and 56 / 0.2 times the flow rate (kg / s) of the pressurized NCG mixture (G1); H ２ S and CO ２ And H ２ , N ２ , C.H. ４ and / or Ar from the pressurized NCG mixture (G1). ２ At least a portion of S and the CO ２ by absorption of at least 50% of the water into the water stream (W2), The H ２ At least a portion of S and the CO ２ At least 50% of the H ２ , N ２ , C.H. ４ and / or Ar, and a dissolved H equivalent to the water stream (W2) is separated from at least a portion of at least one of the water streams (W1, W2, W3, W4, W5, W6, W7, W8, W9, W10, W11, W12, W13, W14, W15, W16, W17, W18, W19, W20, W21, W22, W23, W24, W25, W26, W27, W28, W29, W30, W31, W32, W33, W34, W35, W36, W37, W38, W39, W40, W41, W42, W43, W44, W45, W46, W47, W48, W50, W51, W52, W63, W64, W75, W86, W97, W98, W ２ S and CO ２ A water stream (W4) enriched with H ２ S and CO ２ And H ２ , N ２ , C.H. ４ and / or Ar, compared to the NCG mixture (G1), ２ At least a portion of S and CO ２ a pressurized gas stream (G3) in which at least 50% of Dissolved H ２ S and CO ２ The water stream (W4) enriched with an injection well for injecting said water stream (W4) into a geological reservoir; or for injecting said water stream (W5) into a geological reservoir, in order to use said water stream (W4) as an aid in adjusting the pH of said water stream (W5); The method includes:

2. H ２ S and CO ２ And H ２ , N ２ , C.H. ４ 2. The method according to claim 1, wherein the pressure of the pressurized NCG mixture (G1), which also contains at least one of: Ar; and / or H 2 O, is between 6 and 12 bar.

3. 2. The method according to claim 1, wherein the pressure of the pressurized NCG mixture (G1) is between 7 and 11 bar.

4. 3. The method according to claim 1 or 2, wherein the pressure of the pressurized NCG mixture (G1) is 7, or 8, or 9, or 10, or 11 bar.

5. H ２ S and CO ２ And H ２ , N ２ , C.H. ４ and Ar.

6. 6. The method according to claim 1, wherein the temperature of the NCG mixture (G1) is from 35 to 50° C.

7. The method according to any one of claims 1 to 6, wherein the temperature of the NCG mixture (G1) is between 39 and 41°C.

8. The method according to any one of claims 1 to 7, wherein the temperature of the NCG mixture (G1) is 40°C.

9. The method according to any one of the preceding claims, wherein the temperature of the water stream (W2) is between 4 and 40°C.

10. 10. The method according to any one of the preceding claims, wherein the temperature of the water stream (W2) is between 6 and 35°C.

11. The method according to any one of the preceding claims, wherein the temperature of the water stream (W2) is between 8 and 30°C.

12. The method according to any one of the preceding claims, wherein the temperature of the water stream (W2) is between 10 and 25°C.

13. The method according to any one of the preceding claims, wherein the temperature of the water stream (W2) is between 12 and 20°C.

14. The method according to any one of the preceding claims, wherein the temperature of the water stream (W2) is between 13 and 17°C.

15. The method according to any one of the preceding claims, wherein the temperature of the water stream (W2) is 15°C.

16. H ２ S and CO ２ And H ２ , N ２ , C.H. ４ The method according to any one of the preceding claims, wherein the flow rate of the NCG mixture (G1), also comprising at least one of: Ar; and / or H, is between 0.2 and 1.5 kg / s.

17. The method according to any one of the preceding claims, wherein the flow rate of the NCG mixture (G1) is between 0.25 and 1.45 kg / s.

18. 18. The method according to any one of the preceding claims, wherein the flow rate of the NCG mixture (G1) is between 0.4 and 1.4 kg / s.

19. The method according to any one of the preceding claims, wherein the flow rate of the NCG mixture (G1) is 1 kg / s.

20. The method according to any one of the preceding claims, wherein the flow rate of the water stream (W2) is between 36 and 56 kg / s.

21. The method according to any one of the preceding claims, wherein the flow rate of the water stream (W2) is between 45 and 55 kg / s.

22. The method according to any one of the preceding claims, wherein the flow rate of the water stream (W2) is between 48 and 52 kg / s.

23. The method according to any one of the preceding claims, wherein the flow rate of the water stream (W2) is 50 kg / s.

24. H ２ S and CO ２ And H ２ , N ２ , C.H. ４ The method according to any one of claims 1 to 23, wherein the NCG mixture (G1) also containing at least one of: Ar; and / or Ar is a geothermal non-condensable gas mixture.

25. Hydrogen sulfide (H ２ S) and carbon dioxide (CO ２ ) and H ２ , N ２ , C.H. ４ and / or Ar from a non-condensable gas (NCG) mixture (G1) ２ At least a portion of S and CO ２ 1. A system for removing at least 50% of a H ２ S and CO ２ And H ２ , N ２ , C.H. ４ and / or Ar, pressurizing the NCG mixture (G1) to a pressure of 6 to 20 bar; H ２ S and CO ２ And H ２ , N ２ , C.H. ４ and / or Ar is contacted with a water flow (W2), the pressure of which is between 6 and 23 bar and the flow rate (kg / s) of which is between 36 / 1.5 and 56 / 0.2 times the flow rate (kg / s) of said pressurized NCG mixture (G1), H ２ S and CO ２ And H ２ , N ２ , C.H. ４ and / or Ar from the pressurized NCG mixture (G1). ２ At least a portion of S and the CO ２ The H ２ At least a portion of S and the CO ２ At least 50% of the H ２ , N ２ , C.H. ４ and / or Ar, and a dissolved H equivalent to the water stream (W2) is separated from at least a portion of at least one of the water streams (W1, W2, W3, W4, W5, W6, W7, W8, W9, W10, W11, W12, W13, W14, W15, W16, W17, W18, W19, W20, W21, W22, W23, W24, W25, W26, W27, W28, W29, W30, W31, W32, W33, W34, W35, W36, W37, W38, W39, W40, W41, W42, W43, W44, W45, W46, W47, W48, W50, W51, W52, W63, W64, W75, W86, W97, W98, W ２ S and CO ２ A water stream (W4) enriched with H ２ S and CO ２ And H ２ , N ２ , C.H. ４ and / or Ar, compared to the NCG mixture (G1), ２ At least a portion of S and CO ２ a pressurized gas stream (G3) in which at least 50% of Dissolved H ２ S and CO ２ The water stream (W4) enriched with an injection well configured to inject said water flow (W4) into a geological reservoir; or a system configured to inject said water stream (W5) into a geological reservoir for use of said water stream (W4) as an aid in adjusting the pH of said water stream (W5); The system that is configured.

26. 26. The system of claim 25, comprising: In the absorption tower, H ２ S and CO ２ And H ２ , N ２ , C.H. ４ and / or Ar, contacting the pressurized NCG mixture (G1) stream with a water stream (W2); In the absorption tower, H ２ S and CO ２ And H ２ , N ２ , C.H. ４ and / or Ar from the pressurized NCG mixture (G1). ２ At least a portion of S and the CO ２ The H ２ At least a portion of S and the CO ２ At least 50% of the H ２ , N ２ , C.H. ４ and / or Ar, and a dissolved H equivalent to the water stream (W2) is separated from at least a portion of at least one of the water streams (W1, W2, W3, W4, W5, W6, W7, W8, W9, W10, W11, W12, W13, W14, W15, W16, W17, W18, W19, W20, W21, W22, W23, W24, W25, W26, W27, W28, W29, W30, W31, W32, W33, W34, W35, W36, W37, W38, W39, W40, W41, W42, W43, W44, W45, W46, W47, W48, W50, W51, W52, W63, W64, W75, W86, W97, W98, W ２ S and CO ２ A water stream (W4) enriched with H ２ S and CO ２ And H ２ , N ２ , C.H. ４ and / or Ar, compared to the NCG mixture (G1), ２ At least a portion of S and CO ２ and a pressurized gas flow (G3) in which at least 50% of The system that is configured.

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