Method of monitoring and / or verifying carbon dioxide mineralisation

Abstract

A method of monitoring carbon dioxide (CO2) mineralisation and / or dissolution in a storage reservoir comprises: injecting a feed of carbon dioxide into the storage reservoir, wherein the feed has a first ratio of 13C / 12C, a first ratio of CO2 to a noble gas, and a first ratio of 18O / 16O; producing a fluid downstream of the storage reservoir, wherein the produced fluid has a second ratio of 13C / 12C, a second ratio of CO2 / noble gas, and a second ratio of 18O / 16O; and measuring the second ratio of 13C / 12C of the produced fluid and measuring the second ratio of CO2 to noble gas and / or measuring the second ratio of 18O / 16O of the produced fluid.

Description

[0001] Method of monitoring and / or verifying carbon dioxide mineralisationField of the Invention The present invention relates to a method for monitoring and / or verifying carbon dioxidemineralisation in a storage reservoir, e.g. in a subterranean formation. to the Intergovernmental Panel on Climate Change (IPCC) and the UKClimate Change Committee (CCC), gigaton-scale capture, removal and storage of carbondioxide (CO2) is now unavoidable if the world is to reach net zero greenhouse gas (GHG) emissions and limit global warming to below 1.5-2°C. Emerging carbon capture and storage (CCS) and carbon dioxide removal (CDR) markets require robust and deployable methods for monitoring, reporting and verifying (MRV) CO2storage for respective projects. Durable and verifiable storage is essential to ensure CO2is permanently isolated from the atmosphere and accurately accounted for. Subsurface geological reservoirs are known tooffer secure storage of CO2 for millennia and can be closely monitored using establishedmethods of subsurface investigation. The majority of active and planned CO2storage projects use sedimentary reservoir lithologies, where vertical migration of buoyant CO2 is prevented by physical trapping mechanism such as impermeable cap rocks and capillary forces in residual pore space. In recent years mafic and ultramafic rock formations have become increasingly of interest for CO2storage because of their capacity to rapidly immobilise CO2in carbonateminerals through a process called carbon mineralisation. To utilise this means of CO2 storage,the CO2 to be stored is injected as either a free phase where it dissolves in water, or is injectedin the dissolved phase, eliminating its inherent buoyancy, before reacting with divalent cations(e.g. Ca2+ / Mg2+ / Fe2+) present in reservoir rocks that bind with aqueous CO2 to form carbonate minerals (e.g. calcium carbonate, magnesium carbonate, or ferrous carbonate). The key advantage of carbon mineralisation is that sequestered CO2 is immobilised and cannot escape back to the atmosphere, thus reducing global warming. In-situ CO2 mineralisation in basalticrocks could offer secure storage for 10 to 100 times more CO2 than will be emitted bycombustion of all fossil fuels remaining on Earth. However, it is difficult to track the long-term fate of CO2 injected into subsurface basaltic rocks because injected CO2 can also remain dissolved in fluids. Monitoring and verification of in-situ CO2 mineralisation typically uses shifts in geochemical indicators to track and quantify storage. Conventional techniques use reactiveand non-reactive indirect (e.g., pH, dissolved and cation concentrations) and / or added(e.g.,14C, SF6, or 1-naphthalenesulfonic acid sodium salt (1-ns)) tracers for storageverification. However, these techniques rely on assumptions about the fate of CO2, or, in thecase of added tracers, can only be used sparsely because of the cost of use and environmentalrestrictions. It is an object of the invention to address and / or mitigate one or more problems associated with the prior art. It is an object of the invention to provide a reliable and affordable method of monitoring, e.g. quantifying, carbon dioxide mineralisation in a storage reservoir, e.g. in a subterranean formation. The present invention is based on the finding that quantification of carbon dioxidecapture through dissolution into water and / or storage through mineralisation as carbonateminerals may be achieved through the use of differing fractionation of certain inherentsubstances in carbon dioxide, such as carbon isotopes and / or noble gases, whenmineralisation and / or dissolution of carbon dioxide occurs in situ or on the surface. Thus, thepresent invention is based on monitoring the fractionation in those substances between a feed of carbon dioxide injected into a storage reservoir and a produced stream of fluid downstream of the storage reservoir. According to a first aspect, there is provided a method of monitoring carbon dioxide mineralisation and / or dissolution in a storage reservoir, the method comprising: injecting a feed of carbon dioxide into the storage reservoir, wherein the feed has a first13C / 12C ratio; producing a fluid downstream of the storage reservoir; and measuring the13C / 12C ratio of the produced fluid. The produced fluid may have a second13C / 12C ratio. When carbon dioxide in the feed is mineralised and / or dissolved in the storagereservoir, the second13C / 12C ratio may be different from the first13C / 12C ratio. The difference in the second13C / 12C ratio and the first13C / 12C ratio may be representative of mineralisation and / or dissolution of the carbon dioxide injected into the storage reservoir, e.g. between at least one injection well and at least one production well. The method may comprise quantifying the amount of carbon dioxide mineralisation and / or dissolution in the reservoir based on a comparison, e.g. a difference, differencebetween the first 13C / 12C ratio and the second 13C / 12C ratio.Advantageously, the inventors have that the change or shift in the ratios ofnatural, inherent isotopes, and in particular13C / 12C, between an injected feed and a produced fluid, may be used to determine the percentage of CO2mineralised and / or dissolved in a storage reservoir. Without wishing to be bound by theory, it is believed that when CO2 ismineralised and / or dissolved, 13C and 12C fractionate and the 13C / 12C ratio shifts by amagnitude proportional to the fraction of CO2 mineralised and / or dissolved in the storagereservoir, which is also dependent on the in-situ temperature and pH. In particular, when CO2is mineralised and / or dissolved,12C can be preferentially sequestered into the mineralised CO2(e.g. as the carbonate mineral calcite (CaCO3)) in preference to 13C, or vice-versa, dependingon the in-situ temperature and pH. Therefore, measuring a shift in 13C / 12C ratios between afeed of CO2and a produced fluid downstream of the storage reservoir may provide a reliable indicator of the level of CO2mineralised and / or dissolved in the storage reservoir. In addition, the direction and magnitude of ratio shifts may permit differentiation between CO2mineralisation and dissolution. Advantageously,13C and12C are the natural inherent isotopes of carbon, which means that the present method does not require the addition of external and / or artificial substances such as14C, SF6, or 1-ns tracers, to the feed. The method may comprise determining and / or measuring the13C / 12C ratio in the feed. The method may comprise determining the difference or shift in the13C / 12C ratio between the feed and the produced fluid. The method may comprise determining, based on the difference or shift in the13C / 12C ratio between the feed and the produced fluid, a level of CO2mineralisation and / or dissolution in the storage reservoir. The method may comprise using calibration data. The method may comprise performing calibration of the storage reservoir. It will be understood that a / the storage reservoir includes substances and / or fluids, some of which will be displaced by the injection of the feed and produced in the produced fluid. Thus, the produced fluid may typically comprise a mixture of background fluids and injected feed. Therefore, without wishing to be bound by theory, this means that any fractionation resulting from capture (e.g. mineralisation and / or dissolution of injected CO2) may be affected by the geochemical signature of background CO2 in the storage reservoir. Calibration may allow a user to account for the geochemical signature of background fluids in the reservoir inthe measurement made on the produced fluid.Calibration may comprise injecting a calibration feed into the storage reservoir, e.g. via (the) at least one injection well, and producing a calibration fluid downstream of the storage reservoir, e.g. via (the) at least one producing e.g. (the) at least one production well and / or monitoring well. The calibration feed may comprise at least one tracer. The calibration feed may comprise a natural and / or inherent tracer, e.g.13C,18O, or a noble gas. The calibration feed may comprise an added or artificial tracer, e.g.14C, SF6, or 1-ns. Calibration may comprise determining and / or measuring at least one tracer concentration in the calibration feed, and determining and / or measuring the13C / 12C ratio in the produced calibration fluid. The calibration data may comprise data indicating a difference or shift in the13C / 12C ratio between a calibration feed and a produced fluid downstream of the storage reservoir. Typically, the calibration feed may comprise or may be a fluid, e.g. an aqueous fluid,free or substantially free of carbon dioxide.The calibration feed may comprise or may be an aqueous fluid such as water, e.g. freshwater, saltwater, subterranean water, brine, or the like. The method may comprise applying the calibration data, to the difference or shift in the13C / 12C ratio between the feed and the produced fluid. The method may further comprise determining the percentage of CO2mineralised and / or dissolved in a storage reservoir. The method may comprise or may further comprise monitoring and / or measuring a shift in the ratio of CO2 to a noble gas, between the feed and the produced fluid. Preferably, the noble gas may not be radon. The noble gas isotope may be an isotope of a noble gas selected from helium (He), neon (Ne), argon (Ar), krypton (Kr) or xenon (Xe). Typically, the noble gas may be helium. The noble gas isotope may be an isotope of helium, typically3He. Advantageously, the inventors have discovered that the change or shift in the ratios of CO2 and natural, inherent noble gas or isotope thereof (e.g.3He), between an injected feed and a produced fluid, may be used to determine the percentage of CO2 mineralised and / or dissolved in a storage reservoir. Without wishing to be bound by theory, it is believed that when CO2 is mineralised and dissolved, CO2 / noble gas ratios decrease by a magnitude proportional to the fraction of CO2 mineralised and / or dissolved in the storage reservoir. Therefore, measuring a shift in CO2 / noble gas ratios between a feed of carbon dioxide and a produced fluid downstream of the storage reservoir may provide a reliable indicator of the level of CO2 mineralised and / or dissolved in the storage reservoir. Advantageously, the monitoring of CO2 / 3He ratio allows a comparison of CO2 behaviour relative to a substance which is unreactive in the storage reservoir is therefore unaffected by mineralisation. The feed may have a first ratio of CO2 / noble gas. The method may comprise determining and / or measuring the (first) ratio of CO2 / noblegas in the feed.The method may comprise determining and / or measuring the ratio of CO2 / noble gas in the produced fluid. The produced fluid may have a second ratio of CO2 / noble gas. The method may comprise determining the difference or shift in the CO2 / noble gas ratio between the feed and the produced fluid. The method may comprise determining, based on the difference or shift in the CO2 / noble gas ratio between the feed and the produced fluid, a level of CO2mineralisation and / or dissolution in the storage reservoir. The method may comprise quantifying the amount of carbon dioxide mineralisation and / or dissolution in the reservoir based on a comparison, e.g. a difference, difference between the first CO2 / noble gas ratio and the second CO2 / noble gas ratio. The method may comprise using calibration data. The method may comprise performing calibration of the storage reservoir. It will be understood that a / the storage reservoir includes substances and / or fluids (independent from the injected fluids), some of which will be displaced by the injection of the feed and produced in the produced fluid. Thus, the produced fluid may typically comprise a mixture of background fluids and injected feed. Therefore, without wishing to be bound bytheory, this means that any fractionation resulting from capture and / or storage (e.g.mineralisation and / or dissolution of injected CO2) may be affected by the geochemical signature of background CO2in the storage reservoir. Calibration may allow a user to account for the geochemical signature of background fluids in the reservoir in the measurement made on the produced fluid. Calibration may comprise injecting a calibration feed into the storage reservoir, e.g. via (the) at least one injection well, and producing a calibration fluid downstream of the storagereservoir, e.g. via (the) at least one producing well, e.g. (the) at least one production well and / ormonitoring well. The calibration feed may comprise at least one tracer. The calibration feed may comprise a natural and / or inherent tracer, e.g.13C,18O, or a noble gas. The calibration feed may comprise an added or artificial tracer, e.g.14C, SF6, or 1-ns. Calibration may comprise determining and / or measuring the ratio of CO2 / noble gas inthe calibration feed, and determining and / or measuring the ratio of CO2 / noble gas in theproduced calibration fluid. The calibration data may comprise indicating a difference or shift in the ratio of CO2 / noble gas between a calibration feed and a produced fluid downstream of the storage reservoir. Typically, the calibration feed may comprise or may be a fluid, e.g. an aqueous fluid, free of substantially free of carbon dioxide. The calibration feed may comprise or may be an aqueous fluid such as water, e.g. freshwater, saltwater, subterranean water, brine, or the like. The method may comprise comparing the difference or shift in the ratio of CO2 / noblegas between the feed and the produced fluid, to the calibration data. The method may furthercomprise determining the percentage of CO2mineralised and / or dissolved in a storage reservoir. Thus, in an embodiment of the first aspect, there is provided a method of monitoring carbon dioxide mineralisation and / or dissolution in a storage reservoir, the method comprising: injecting a feed of carbon dioxide into the storage reservoir; producing a fluid downstream of the storage reservoir; monitoring and / or measuring a shift in the13C / 12C ratio, between the feed and the produced fluid; and monitoring and / or measuring a shift in the ratio of CO2to a noble gas, between the feed and the produced fluid. The method may comprise or may further comprise monitoring and / or measuring a shift in the ratio of18O / 16O, between the feed and the produced fluid. Advantageously, the method may comprise determining whether the produced fluid includes fluid, e.g. water, injected in the feed, or whether the produced fluid includes background fluid only (e.g. fluid displaced from the storage reservoir). Without wishing to be bound by theory, it is believed that, because CO2 constitutes a minor fraction of the overall oxygen isotope pool in the storage reservoir, any shift in the ratio of18O / 16O, between the feed and the produced fluid, can be considered to be almost entirely unrelated to the behaviour, e.g. mineralisation, of CO2. In particular, detecting a shift in the ratio of18O / 16O may indicate that the produced fluid contains at least a portion of the injectedfeed, which may help distinguish between injected feed and background signals in theproduced fluid. In other words, a shift in the ratio of18O / 16O (δ18OH2O) may be used as a tracer of the injected feed, particularly when the feed is an aqueous fluid. The ratio of18O / 16O is not affected by mineralisation of CO2, because δ18OH2O is only controlled by water. Thus, for example, detection of a shift in the ratio of18O / 16O may indicate that the injected fluids arebeing produced, whilst a shift in the 13C / 12C ratio (δ13CCO2) that is characteristic of mineralisationwould provide two separate indicators confirming the occurrence of mineralised of CO2. In other words, using the ratio of18O / 16O as a of monitoring the (non-reactive) carrier of the carbon dioxide injected in the feed, enables a user to ensure any shift in the13C / 12C ratio relates to mineralisation of carbon dioxide and not, for example, to background interference or other similar phenomena. The feed may have a first18O / 16O ratio. The method may comprise measuring the18O / 16O ratio in the produced fluid. The produced fluid may have a second18O / 16O ratio. The method may comprise determining the difference or shift in the18O / 16O ratio between the feed and the produced fluid. The method may comprise determining, based on the difference or shift in the18O / 16O ratio between the feed and the produced fluid, the status or level of the injected feed being produced in the produced fluid. The method may comprise quantifying the amount of carbon dioxide mineralisation and / or dissolution in the reservoir based on a comparison, e.g. a difference, between the first18O / 16O ratio and the second18O / 16O ratio. The method may comprise using calibration data. The calibration data may comprisedata indicating a difference or shift in the 18O / 16O ratio between a calibration feed and aproduced fluid downstream of the storage reservoir. Typically, the calibration feed may comprise or may be a fluid, e.g. an aqueous fluid, free of substantially free of carbon dioxide. The calibration feed may comprise or may be an aqueous fluid such as water, e.g. freshwater, saltwater, subterranean water, brine, or the like. Thus, in an embodiment of the first aspect, there is provided a method of monitoring carbon dioxide mineralisation and / or dissolution in a storage reservoir, the method comprising: injecting a feed of carbon dioxide into the storage reservoir; producing a fluid downstream of the storage reservoir; monitoring and / or measuring a shift in the13C / 12C ratio, between the feed and the produced fluid; and monitoring and / or measuring a shift in the18O / 16O ratio, between the feed and the produced fluid. The following features may be applicable to any of the above or subsequent aspects.The storage reservoir may comprise or may be a subterranean formation. The storage reservoir may comprise or may be a basaltic rock formation and / or a maficor ultramafic rock formation. Advantageously, these rock types have high concentrations ofmetals, e.g. divalent cations, capable of reacting with dissolved carbon dioxide (carbonate) toyield mineralisation in situ, and have low silica levels.The method may comprise injecting the feed continuously. The method may comprise injecting feed intermittently. The method may comprise producing the fluid downstream of the storage reservoir continuously. The method may comprise producing the fluid downstream of the storage reservoir intermittently, e.g. at predetermined, regular, or irregular time intervals. The method may comprise injecting the feed via at least one injection well. The method may comprise producing the fluid via at least one production well or monitoring well. Typically, the storage reservoir may be located between the at least one injection welland the at least one production well or monitoring well.The feed of carbon dioxide may comprise or may be an injection fluid. The method may comprise determining and / or measuring the13C / 12C ratio in the injection fluid. The method may comprise preparing the injection fluid. The method may comprise dissolving carbon dioxide into a fluid, e.g. an aqueoussolution, to prepare the injection fluid. Preferably, the injection fluid may be an aqueous solution. In such instance, dissolution may occur on the surface. For example, dissolution may be performed as disclosed in EP4031267A1 (SIGFÚSSON et al), which is incorporated herein by reference in its entirety. The method may comprise feeding carbon dioxide into an absorption tower, asdisclosed for example in EP4031267A1 (SIGFÚSSON et al), which is incorporated herein by reference in its entirety. The method may comprise feeding an aqueous fluid into the dissolution tower. The method may comprise dissolving at least a portion of the carbon dioxide into the aqueous fluid. The aqueous fluid may comprise or may be an aqueous liquid such as water, e.g.freshwater, saltwater, subterranean water, brine, or the like. Advantageously, the method may comprise feeding the carbon dioxide and the aqueous fluid in a counter-flow arrangement. The method may comprise feeding the carbon dioxide from a lower end or lower portion of the dissolution tower. The method may comprise feeding the aqueous fluid from an upper end or upper portion of the dissolution tower. The method may comprise recovering the injection fluid from the dissolution tower, e.g. from a lower end or lower portion thereof. The method may comprise recovering gas outlet from the dissolution tower, e.g. from an upper end or upper portion thereof. The gas outlet may comprise a portion of the carbon dioxide which has not been dissolved in the aqueous fluid. Advantageously, providing the feed of carbon dioxide as an injection fluid, e.g. an aqueous injection liquid, may allow the shift in13C / 12C ratio to be related to mineralisation, rather than dissolution, since the carbon dioxide injected in the feed is then already in dissolved form. Thus, providing the feed of carbon dioxide as an injection fluid, e.g. an aqueous injection liquid, may avoid the need to differentiate carbon dioxide loss between mineralisation and dissolution. According to a second aspect, there is provided a method of monitoring carbon dioxide mineralisation and / or dissolution in a storage reservoir, the method comprising: injecting a feed of carbon dioxide into the storage reservoir, wherein the feed has a first ratio of CO2to a noble gas; producing a fluid downstream of the storage reservoir; and measuring the ratio of CO2 to noble gas of the produced fluid.Advantageously, the inventors have discovered that the change or shift in the ratios of CO2and natural, inherent noble gas or isotope thereof (e.g.3He), between an injected feed and a produced fluid, may be used to determine the percentage of CO2mineralised and / or dissolved in a storage reservoir. Without wishing to be bound by theory, it is believed that when CO2 is mineralised and dissolved, CO2 / noble gas ratios decrease by a magnitude proportional to the fraction of CO2mineralised and / or dissolved in the storage reservoir. Therefore, measuring a shift in CO2 / noble gas ratios between a feed of carbon dioxide and a produced fluid downstream of the storage reservoir may provide a reliable indicator of the level of CO2mineralised and / or dissolved in the storage reservoir. Advantageously, the monitoring of the CO2 / 3He ratio may allow a comparison of CO2behaviour relative to a substance which is unreactive in the storage reservoir is therefore unaffected by mineralisation. The method may comprise quantifying the amount of carbon dioxide mineralisation and / or dissolution in the reservoir based on a comparison, e.g. a difference, difference between the first CO2 / noble gas ratio and the second CO2 / noble gas ratio. The corresponding features described in relation to the first aspect may equally apply to the second aspect and, merely for brevity, are not repeated here. According to a third aspect, there is provided a method of monitoring carbon dioxide mineralisation and / or dissolution in a storage reservoir, the method comprising: injecting a feed of carbon dioxide into storage reservoir, wherein the feed has a firstratio of 13C / 12C and a first ratio of CO2 to a noble gas;producing a fluid downstream of the storage reservoir; and measuring the ratio of 13C / 12C and the ratio of CO2 to noble gas of the produced fluid.The method may comprise: monitoring and / or measuring a shift in the13C / 12C ratio, between the feed and the produced fluid; and monitoring and / or measuring a shift in the ratio of CO2 to a noble gas, between the feed and the produced fluid. Advantageously, combining monitoring of the 13C / 12C ratio and the ratio of CO2 to noblegas between the feed and the produced fluid, may provide more accurate and / or more reliable information, than using a single marker. For example, using the13C / 12C ratio only may besufficient, but in certain circumstances the changes in the 13C / 12C ratio due to mineralisationmay overlap with other in situ phenomena such as background values or other chemical orphysical reactions, which may cause the mineralisation signal to be “hidden” by these other phenomena. Thus, using an additional marker such as the ratio of CO2 / 3He allows the monitoring of CO2behaviour relative to a substance that in unreactive and unaffected by mineralisation. As a result, if the13C / 12C ratio and the ratio of CO2 / 3He shift by levels that correspond to the same magnitude of mineralisation, then it can be reliably concluded thatmineralisation is the cause. On the other hand, using the ratio of CO2 / 3He can be a reliableindicator of CO2 capture (either by mineralisation or dissolution) but may not allow to differentiate between the specific mechanisms of CO2capture (e.g. between mineralisation and dissolution). Thus, combining monitoring the13C / 12C ratio and the ratio of CO2to noble gas between the feed and the produced fluid, may provide both an accurate method of monitoring CO2capture, and may also allow to differentiate reliably between CO2mineralisation and dissolution.The method may comprise quantifying the amount of carbon dioxide mineralisation and / or dissolution in the reservoir based on a comparison, e.g. a difference, differencebetween the first 13C / 12C ratio and the second 13C / 12C ratio, and on a comparison, e.g. adifference, difference between the first CO2 / noble gas ratio and the second CO2 / noble gas ratio. The corresponding features described in relation to the first aspect may equally apply to the third aspect and, merely for brevity, are not repeated here. According to a fourth aspect, there is provided a method of monitoring carbon dioxidemineralisation and / or dissolution in a storage reservoir, the method comprising: injecting a feed of carbon dioxide into storage reservoir, wherein the feed has a firstratio of 13C / 12C and a first ratio of 18O / 16O;producing a fluid downstream of the storage reservoir; and measuring the ratio of 13C / 12C and the 18O / 16O ratio of the produced fluid.The method may comprise: monitoring and / or measuring a shift in the13C / 12C ratio, between the feed and the produced fluid; and monitoring and / or measuring a shift in the 18O / 16O ratio, between the feed and theproduced fluid. The method may comprise quantifying the amount of carbon dioxide mineralisation and / or dissolution in the reservoir based on a comparison, e.g. a difference, between the first13C / 12C ratio and the second 13C / 12C ratio, and on a comparison, e.g. a difference, differencebetween the first18O / 16O ratio and the second18O / 16O ratio. The corresponding features described in relation to the first aspect may equally apply to the fourth aspect and, merely for brevity, are not repeated here. The features described in relation to any aspect of the invention may equally apply to any other aspect and, merely for brevity, are not repeated. According to another aspect, the present invention relates to a method for monitoringmineralisation of carbon dioxide (CO2) injected into a geological reservoir, the methodcomprising: providing a system comprising: an injection well for injecting fluid into the geological reservoir, and an extraction well arranged a predetermined distance from the injection well, for extracting fluid samples from the geological reservoir, performing a tracer test, in order to: establish that a flow path exists between the injection well and the extraction well, and characterize the flow path by: determining / estimating a period of time it takes a fluid, injected through the injection well into the geological reservoir, to reach the extraction well, determining / estimating a mixing ratio of background reservoir fluid and injected fluid at the extraction well, obtaining background reservoir fluid data including an estimated 13C / 12C ratio of CO2 inthe background reservoir fluid at the extraction well and / or an estimated CO2 to noble gas ratioin the background reservoir fluid at the extraction well,providing an injectate comprising CO2 and noble gas,performing first measurements on the injectate or on a plurality of fluids which has been merged to form the injectate, in order to estimate a13C / 12C ratio of CO2in the injectate and / orto estimate a CO2 to noble gas ratio in the injectate,injecting the injectate into the geological reservoir through the injection well,extracting a mixed fluid sample from the extraction well after the period of time haspassed, the mixed fluid sample comprising a mixture of background reservoir fluid and injectate, performing second measurements on the mixed fluid sample, in order to estimate a13C / 12C ratio of CO2of the mixed fluid at the extraction well and / or to estimate a CO2to noble gas ratio of the mixed fluid at the extraction well, calculating the expected13C / 12C ratio of CO2and / or the expected CO2to noble gasratio of the mixed fluid at the extraction well if no mineralisation of CO2 has occurred betweenthe injection well and the extraction well, based on the estimated mixing ratio at the extraction well, the background reservoir fluid data and the estimated13C / 12C ratio of CO2in the injectateand / or the estimated CO2 to noble gas ratio in the injectate,comparing the expected13C / 12C ratio of CO2and / or the expected CO2to noble gasratio of the mixed fluid at the extraction well with the estimated 13C / 12C ratio of CO2 and / or theestimated CO2 to noble gas ratio of the mixed fluid at the extraction well, respectively, in orderto determine if mineralisation has occurred between the injection well and the extraction welland thereby monitor the mineralisation of carbon dioxide injected into the geological reservoir. As described above, a preferred embodiment of a method according to the presentinvention includes providing a system comprising an injection well for injecting fluid into thegeological reservoir, and an extraction well arranged a predetermined distance from theinjection well, for extracting fluid samples from the geological reservoir. If the injection well andextraction well are connected via a flow path, at least some of the injectate will flow from the injection well to the extraction well. By comparing the13C / 12C ratio of CO2 and / or the CO2 tonoble gas ratio in the injectate and at the extraction well, it can be determined whethermineralisation of CO2 has occurred between the injection well and the extraction well.Because the extraction well is located a predetermined distance from the injection wellwithin the geological reservoir, it will take some time before the injectate reaches the extractionwell after injection into the geological reservoir through the injection well. Thus, fluid samplesshould not be collected from the extraction well before the injectate has travelled through the flow path from the injection well to the extraction well. Thus, the method of the present invention comprises establishing that a flow path existsbetween the injection well and the extraction well and determining / estimating a period of time it takes a fluid, injected through the injection into the geological reservoir, to reach theextraction well. It is possible to determine whether a flow path exists between the injection welland the extraction well by performing a tracer test. Furthermore, it is also possible to determinethe period of time it takes a fluid, injected through the injection well into the geological reservoir, to reach the extraction well, by performing the tracer test. Atracer test may comprise injecting a fluid comprising a known concentration of tracerinto the geological reservoir through the injection well and extracting a plurality of fluid samplesfrom the extraction well at different times and measuring the concentration of tracer in theextracted fluid samples, until the tracer is observed in the extracted fluid samples. The amountof CO2which has disappeared between the injection well and extraction well may indicate thatCO2 mineralisation between the injection well and the extraction well has occurred. However,because the injectate mixes with background reservoir fluid of the geological reservoir when it enters the geological reservoir, fluid extracted from the extraction well is a mixed fluid. The mixing ratio of background reservoir fluid and injectate at the extraction well canalso be determined using the tracer test, if the concentration of the tracer added to the injectateis known. By determining the concentration of the tracer at the extraction well, the dilution rateof the tracer at the extraction well can be determined, and thus the mixing ratio of backgroundreservoir fluid and injectate at the extraction well can be determined.Because the injectate mixes with background reservoir fluid, the13C / 12C ratio of CO2inthe background reservoir fluid at the extraction well and / or the CO2 to noble gas ratio in thebackground reservoir fluid at the extraction well, has to be determined, in order to make surethat a shift in 13C / 12C ratio of CO2 and / or CO2 to noble gas ratio between the injectate and mixedfluid at the extraction well, is caused by mineralisation, not background interference. Based on the estimated mixing ratio at the extraction well, background reservoir fluid data and the estimated13C / 12C ratio of CO2in the injectate and / or the estimated CO2to noblegas ratio in the injectate, an expected 13C / 12C ratio of CO2 and / or an expected CO2 to noblegas ratio of the mixed fluid at the extraction well can be calculated, if no mineralisation of CO2has occurred between the injection well and the extraction well. By comparing the expected CO2 to noble gas ratio in the mixed fluid at the extractionwell, if no mineralisation has occurred, with the estimated CO2 to noble gas ratio in the mixedfluid at the extraction well, it can be determined whether or not mineralisation has occurred.If the estimated CO2 to noble gas ratio in the mixed fluid at the extraction well is the same asthe expected CO2 to noble gas ratio in the mixed fluid at the extraction well, it indicates thatCO2 has not participated in any reactions and that no mineralisation has occurred.If the estimated CO2 to noble gas ratio in the mixed fluid at the extraction well is differentfrom the expected CO2 to noble gas ratio in the mixed fluid at the extraction well, it indicatesthat the CO2 has participated in a reaction, mineralisation, which has shifted the CO2 tonoble gas ratio in the mixed fluid at the extraction well. By comparing the expected13C / 12C ratio of CO2in the mixed fluid at the extraction well,if no mineralisation has occurred, with the estimated 13C / 12C ratio of CO2 ratio in the mixed fluidat the extraction well, it can be determined whether or not mineralisation has occurred.If the estimated 13C / 12C ratio of CO2 in the mixed fluid at the extraction well is the same as theexpected13C / 12C ratio of CO2 in the mixed fluid at the extraction well, it indicates that CO2 hasnot participated in any reactions and that no mineralisation has occurred.If the estimated 13C / 12C ratio of CO2 ratio in the mixed fluid at the extraction well isdifferent from the expected13C / 12C ratio of CO2in the mixed fluid at the extraction well, it indicates that the CO2has participated in a reaction, e.g. mineralisation, which has shifted the13C / 12C ratio of CO2in the mixed fluid at the extraction well. Example:a) Mixing ratio of injectate vs. background reservoir fluid: 20% vs.80% = 1:4b) Background reservoir fluid 13C / 12C ratio of CO2: -2c) Estimated injectate 13C / 12C ratio of CO2: -5d) Estimated 13C / 12C ratio of CO2 in mixed fluid at extraction well: -1,5If no mineralisation occurs between the injection well and the extraction well, theestimated injectate 13C / 12C ratio of CO2 should not change, neither should the estimatedbackground reservoir fluid 13C / 12C ratio of CO2. Thus, the expected 13C / 12C ratio of CO2 in themixed fluid at the extraction well should be somewhere between the estimated 13C / 12C ratio ofCO2 in the background reservoir fluid and the estimated 13C / 12C ratio of CO2 in the injectate.The mixing ratio of background reservoir fluid and injectate is used to determine how much the13C / 12C ratio of CO2 in the background reservoir fluid and the 13C / 12C ratio of CO2 in the injectateeach contribute to the expected 13C / 12C ratio of CO2 in the produced fluid.Background reservoir fluid 13C / 12C ratio of CO2 (when accounting for mixing ratio) =Background reservoir fluid 13C / 12C ratio of CO2*mixing percent of background reservoirfluid / 100= -2*0.8= -1.6Estimated injectate 13C / 12C ratio of CO2 (when accounting for mixing ratio) = Estimatedinjectate 13C / 12C ratio of CO2*mixing percent of injectate / 100= -5*0.2= -1Expected 13C / 12C ratio of CO2 in mixed fluid at extraction well if no mineralisation occurs= Background reservoir fluid 13C / 12C ratio of CO2 + Estimated injectate 13C / 12C ratio of CO2(when accounting for mixing ratio) = -1.6 +(-1) = -2.6 Since the estimated 13C / 12C ratio of CO2 in the mixed fluid (-1.5) at the extraction wellis not equal to the expected 13C / 12C ratio of CO2 in the mixed fluid at the extraction well (-2.6),but higher, this indicates that some has occurred between the injection well andthe extraction well. The above example is only for monitoring the 13C / 12C ratio of CO2. Advantageously,combining monitoring of the13C / 12C ratio of CO2 and the ratio of CO2 to noble gas between the injectate and the mixed fluid at the extraction well, may provide more accurate and / or more reliable information, than using a single marker. In embodiments, monitoring mineralisation of CO2 comprises quantifying the level ofCO2 mineralisation. For mineralisation and carbon isotopes, 13C preferentially partitions intomineralised CO2relative to12C when temperature is <192°C, meaning any remaining CO2is depleted in13C and the13C / 12C ratio decreases. When temperature >192°C this trend inverts.The magnitude of the shifted 13C / 12C ratio of CO2 in the mixed fluid compared to the expected13C / 12C ratio of CO2 in the mixed fluid may further be used to quantify the mineralisation ofCO2. The magnitude of this partitioning is dependent on temperature. Thus, in order to quantifyCO2 mineralisation more precisely, it is important to also know the storage reservoirtemperature. Thus, in embodiments, the method further includes determining / measuring the temperature in the flow path between the injection well and the extraction well and the expected13C / 12C ratio of CO2 is also based on the determined / measured temperature in the flow path.Using this temperature, a fractionation factor (i.e. how much will the isotopesfractionate) can be calculated for carbon isotopes when mineralisation occurs at the storagereservoir temperature. These are derived from established equations that are published in peerreviewed academic literature. Quantifying mineralisation using these fractionation factors isnot a process because it depends on the specific systematics of isotope fractionation.However, in principle it works as follows:If you have an injected CO213C / 12C of +10 and the carbon isotope fractionation factor for13C / 12C at the geological reservoir temperature is +10, then if 90% of the CO2 is mineralised, one would expect the remaining 10% of injected CO2 to have a13C / 12C value of +19. This is a substantial simplification of the process. The magnitude of shift in 13C / 12Cvaries depending on isotope fractionation systematics, mixing with background fluids and the overprinting effect that results from loss of injectate to mineralisation. The variables can all be predicted and constrained. The simplified example is provided for context of how the method works in practise. Thus, in order to improve quantification of CO2 mineralisation, the method preferablycomprise a way to distinguish the signals from injectate and background reservoir fluid.The present inventors have found that detecting a shift in the ratio of18O / 16O of H2O,between the injectate and the mixed fluid at the extraction well, may indicate that the mixedfluid at the extraction well comprises at least a portion of the injectate, which may helpdistinguish between the injectate and signals in the mixed fluid at the extractionwell. In other words, a shift in the ratio of 18O / 16O (δ18OH2O) may be used as a non-reactivetracer of the injectate. The ratio of18O / 16O is not affected by mineralisation of CO2, becauseδ18OH2O is mainly controlled by water values. Thus, detection of a shift in the ratio of 18O / 16Omay indicate that injectate is in fact present in the mixed fluid at the extraction well, whilst ashift in the 13C / 12C ratio (δ13CCO2) and a decrease in CO2 to noble gas ratio indicate thatmineralisation has occurred. Together, these two indications would provide two separateindicators confirming the occurrence of mineralised CO2. In other words, using the ratio of18O / 16O as a way of monitoring the (non-reactive) carrier of the carbon dioxide injectate,enables a user to ensure that any shift in the 13C / 12C ratio of CO2 relates to mineralisation ofcarbon dioxide and not, for example, to background interference or other similar phenomena. Thus, in embodiments of the method according to the present invention, the injectatehas a 18O / 16O ratio of water, which is distinct from the 18O / 16O ratio of water in the backgroundreservoir fluid. In embodiments, the background reservoir fluid data further includes anestimated 18O / 16O ratio of water in the background reservoir fluid at the extraction well andfurthermore, performing the first measurements and the second measurements furthercomprises estimating the 18O / 16O ratio of water in the injectate and in the mixed fluid at theextraction well, respectively. Further embodiments: In embodiments, the tracer test comprises:injecting a fluid comprising a known concentration of tracer into the geological reservoir through the injection well, extracting a plurality of fluid samples from the extraction well at different times andmeasuring the concentration of tracer in the extracted fluid samples, until tracer is detected in a fluid sample. In embodiments, the period of time it takes a fluid, injected through the injection well into the geological reservoir, to reach the extraction well, is determined when the tracer is detected for the first time in a fluid sample, In embodiments, the estimated mixing ratio of background reservoir fluid and injectate at the extraction well is determined by: injecting a tracer fluid with a known concentration of tracer into the geological reservoirand, after the period of time, extracting a fluid sample from the extraction well comprising thetracer, measuring the concentration of tracer in the extracted fluid sample, and comparing the concentration of tracer in the tracer fluid with the concentration of tracer in the extracted fluid sample. The tracer may be a natural and / or tracer, e.g.13C,18O, or a noble gas. The tracer may be an added or artificial tracer, e.g.14C, SF6, or 1-ns. In embodiments, the tracer is a non-reactive tracer, preferably a tracer which is not found in the background reservoir fluid, such as an artificial tracer. In embodiments, the background reservoir fluid data is obtained by: extracting abackground fluid sample consisting of background reservoir fluid from the geological reservoir, preferably from the extraction well, and performing background measurements on the background fluid sample, in order to estimate the13C / 12C ratio of CO2 in the backgroundreservoir fluid and / or in order to estimate the CO2 to noble gas ratio in the background reservoirfluid and / or the background 18O / 16O ratio of water in the background reservoir fluid.In embodiments, the estimated 13C / 12C ratio of CO2 in the background reservoir fluid isindicative of the13C / 12C ratio of CO2in the background reservoir fluid at the extraction well, when no injectate is present and / or the estimated CO2to noble gas ratio in the background reservoir fluid is indicative of the background CO2to noble gas ratio of the background reservoirfluid at the extraction well, when no injectate is present and / or the estimated 18O / 16O ratio ofwater, indicative of the 18O / 16O ratio of water in the background reservoir fluid at the extractionwell, when no injectate is present. In such embodiments, the background measurements are preferably performed on the background reservoir fluid extracted from the extraction well, before any fluid e.g. injectate has been injected into the injection well. In other embodiments, it is assumed that the background reservoir fluid data is the same over a large area of the geological reservoir, and the background measurements are performed on fluid samples extracted from other extraction wells where there is no mixing of background reservoir fluid and injectate, but only background reservoir fluid. In alternative embodiments, a fluid comprising no CO2and noble gas may have been injected into the injection well when the background measurements are taken. If this is the case, the background reservoir data already accounts for the mixing ratio of background reservoir fluid and injectate and it is not necessary to account for the mixing ratio when calculating the expected13C / 12C ratio of CO2 and / or the expected CO2 to noble gas ratio. In embodiments, performing the first measurements includes performing direct orindirect measurement which can be used to estimate the total amount of 12C and 13C of CO2and / or the total amount of CO2 and noble gas and / or the total amount of18O and16O of water in the injectate or in one or more of the plurality of fluids which has been merged to form the injectate. In embodiments, the extracted fluid sample is separated into different phases, beforeperforming the second measurements on the extracted fluid sample, wherein performing thesecond measurements includes performing direct or indirect measurement which can be usedto estimate the total amount of 12C and 13C and / or the total amount of CO2 and noblegas and / or the total amount of 18O and 16O of water in the mixed fluid at the extraction well.In embodiments, the total amount of CO2 includes CO2(g) and / or dissolved inorganiccarbon (DIC) comprising CO2(aq) H2CO3, HCO3-, CO32-. In embodiments, the total amount of12C and13C of CO2 includes CO2(g) and / or dissolved inorganic carbon (DIC) comprising CO2(aq) H2CO3, HCO3-, CO32-. In embodiments, the total amount of noble gas consists of noble gas(g).In embodiments, the total amount of 18O and 16O of water does not include 18O and 16Oof CO2. In embodiments, performing the first measurements and / or the second measurementsincludes using mass spectroscopy and / or gas chromatography. In embodiments, the injectate is provided by merging a plurality of fluids including afirst fluid, a second fluid and third fluid at controlled ratios. In embodiments, the first fluid is a steam condensate obtained from a geothermal powerplant, the second fluid is a gas stream comprising non-condensable gases obtained from thegeothermal power plant and the third fluid is separated water, such as brine, obtained from thegeothermal power plant. In embodiments, the noble gas is Helium, such as 3He or 4He. In other embodiments,the noble gas is Neon or Argon, such as 20Ne or 36Ar. The choice of noble gas depends on thecomposition of the injectate, such as the source of CO2, and which noble gases naturally occurs in the injectate. In embodiments, the geological reservoir comprises or is a subterranean formation,such as a basaltic rock formation and / or a mafic or ultramafic rock formation.In embodiments, the geological reservoir comprises a network of flow paths comprising abackground reservoir fluid. In some embodiments, the method may comprise a plurality of extraction wells locatedat different predetermined distances / locations from the injection well within the geologicalreservoir. In such embodiments, the method may include extracting a mixed fluid sample fromeach of the plurality of extraction wells in order to estimate / determine a 13C / 12C ratio of CO2, aCO2 to noble gas ratio and a 18O / 16O ratio of water at each location.In geological storage, CO2 is typically monitored by comparing reactive components to non-reactive components. Previously these tracers were added substances; for example,14C (radiocarbon) as a reactive tracer and naphthalene disulfonates (NDS) as a non-reactive tracer. The present invention uses the inherent chemical properties of injected CO2 in the same way, in which13C / 12C ratio acts as a reactive tracer, and the CO2 / noble gas ratio and / or18O / 16O ratio of water act as non-reactive tracers. Definitions: In the context of the present invention, the term feed may be used interchangeably withthe term injectate. Both terms are referring to a fluid comprising CO2 (and noble gas such as3He) injected into a geological reservoir through an injection well. Preferably the feed / injectatefurther comprises water and the CO2 is dissolved in the water. Preferably, the feed / injectate isa single-phase fluid. The injectate may be provided by merging a plurality of fluids, preferablyat controlled ratios. These fluids may e.g. include a steam condensate obtained from a geothermal power plant, a gas stream comprising non-condensable gases obtained from the geothermal power plant and separated water, such as brine, obtained from the geothermal power plant. In the context of the present invention, the term produced fluid may be usedinterchangeably with the term mixed fluid. Both terms refers to a fluid comprising a mixture ofbackground reservoir fluid and injectate / feed. The produced fluid / mixed fluid may be extractedfrom an extraction well arranged a predetermined distance from the injection well where theinjectate / feed is injected and analysed in order to determine whether mineralisation of CO2 hasoccurred between the injection well and extraction well. In the context of the present invention, producing a fluid downstream of the storage reservoir, may be understood as the natural mixing of the injectate / feed with the background reservoir fluid in the geological reservoir at a location different than the injection well. In this way, a mixed fluid comprising injectate / feed and background reservoir fluid is formed / produced within the geological reservoir, as a result of injection of the injectate / feed. In the context of the present invention, the term background reservoir fluid is to beunderstood as fluid present within the flow paths of the geological reservoir before fluid isinjected through the injection well into the geological reservoir and mixes with the background reservoir fluid to form a mixed fluid / produced fluid. The mixing ratio of background reservoir fluid and injectate may be determined by injecting a tracer fluid with a known concentration into the geological reservoir and extracting a fluid sample at the extraction area comprising the tracer, measuring the concentration of tracer in the extracted fluid sample, and comparing the concentration of tracer in the tracer fluid with the concentration of tracer in the extracted fluid sample. In the context of the present invention, the terms injection well and reinjection well areused interchangeably and are to be understood as any kind of structure providing for apossibility of placing a fluid, such as the injectate / feed, underground in a downwardly direction,such as e.g. a device that places fluid into rock formations, such as basalt or basaltic rock, and porous rock formations, such as sandstone or limestone, or into or below the shallow soil layer. In the context of the present term extraction well is to be understood as any kind of structure providing for a possibility of extracting fluids or fluid samples from deepunderground in an upward direction, such as e.g. a device that extracts fluids from a geologicalreservoir comprising rock formations, such as basalt or basaltic rock, and porous rock formations, such as sandstone or limestone, or from below the shallow soil layer. The term extraction well includes both production wells and monitoring wells. In the context of the present invention, the term geological reservoir may be usedinterchangeably with the term geothermal reservoir and the term storage reservoir. In thecontext of the present invention the term geological / geothermal / storage reservoir is to beunderstood as an underground structure, e.g. basaltic rock, comprising fractures that expands in other directions than upwardly and downwardly. The fracture networks are integral to the permeability of the geological reservoir. These fracture networks are filled with background reservoir fluid, which mixes with injected fluid / injectate when it enters the geological reservoir. In the context of the present invention, the term estimated ratio (e.g. estimated 13C / 12Cratio of CO2in injectate or estimated CO2to noble gas ratio of the mixed fluid) refers to a ratio which is either measured or calculated based on several measurements and possibly assumptions. Estimated ratios may also be referred to as determined ratios. Brief Description of Drawings Embodiments of the invention are described with reference to the accompanying drawings, in which: Figure 1 shows a schematic diagram of a phase separation system for a fluid producedfrom a monitoring well, according to an embodiment; Figure 2 is a graph showing 3He / 4He ratios normalised to atmosphere (RA) plottedagainst4He / 20Ne, showing binary mixing between a primary magmatic (RA= 15.1;4He / 20Ne >35) and secondary meteoric water (RA = ~1;4He / 20Ne = ~0.3) component. Local mantle R / RA is derived using an inverse mixing hyperbola calculation; Figure 3 is a graph showing CO2 / 3He plotted against stable carbon isotope ratios (δ13C)of CO2 relative to the Vienna Pee Dee Belemnite (VPDB) standard; Figure 4 is a graph showing oxygen (δ18O) and hydrogen (δ2H) isotope ratios of H2Ofrom equilibrated samples in Table 3 reported relative to the Vienna Standard Mean OceanWater (VSMOW) standard; Figure 5 is a graph modelling evolution of gas inlet CO2 / 3He and δ13CCO2 as CO2dissolves in the scrubbing tower and the resulting CO2 / 3He and δ13CCO2 of the dissolved CO2;Figure 6(A): Modelled expected CO2 / 3He and δ13CCO2 for monitoring wells if nomodification of CO2 occurs in the reservoir, calculated using the background mixing ratios ofTable 1 and the relative concentrations of DIC in the injectate and background reservoir fluids;Figure 6(B): Modelled evolution of CO2 / 3He and δ13CCO2 as CO2 is mineralisedin the Carbfix storage reservoir;Figure 7(A): Modelled expected δ13CCO2 and δ18OH2O for monitoring wells if nomodification of CO2 occurs in the reservoir, calculated using the background mixing ratios ofTable 1 and the relative concentrations of DIC in the injectate and background reservoir fluids;Figure 7(B): Modelled evolution of injectate δ13CCO2 and δ18OH2O as CO2 is mineralised and fluids mix in the storage reservoir. Figure 8: Illustrates a schematic diagram of a system comprising a production well forextracting hot fluid from a geological reservoir, a geothermal power plant for producing power,a scrubbing tower for dissolving CO2 in a condensate, and an injection well for injecting aninjectate comprising CO2back into the geological reservoir. In embodiments, the method ofthe present invention is used for monitoring mineralisation of CO2 injected into a geologicalreservoir via. a system in accordance with Figure 8. Detailed Description In the present disclosure, reference is made to a number of terms, which have the meanings provided below, unless a context indicates to the contrary. The nomenclature used herein for defining compounds, in particular the compounds according to the invention, is in general based on the rules of the IUPAC organisation for chemical compounds, specifically the “IUPAC Compendium of Chemical Terminology (Gold Book)”. For the avoidance of doubt, if a rule of the IUPAC organisation is in conflict with a definition provided herein, the definition herein is to prevail. Furthermore, if a compound structure is in conflict with the name provided for the structure, the structure is to prevail. The term “comprising” or variants thereof is to be understood herein to imply the inclusion of a stated element, integer or step, or group of elements, integers or steps, but not the exclusion of any other element, integer or step, or group of elements, integers or steps. The term “consisting” or variants thereof is to be understood to imply the inclusion of a stated element, integer or step, or group of elements, integers or steps, and the exclusion of any other element, integer or step or group of elements, integers or steps. The term “about” herein, when qualifying a number or value, is used to refer to values that lie within ± 5% of the value specified. For example, if a temperature is specified to be about 5 to about 13 °C, temperatures of 4.75 to 13.65 °C are included. Reference to physical states of matter (such as liquid or solid) refer to the matter’s state at 25 °C and atmospheric pressure unless the context dictates otherwise. Energy production is one of the major CO2 emission sources, contributing significantlyto global greenhouse gas emissions and climate change. Geothermal power plants are one means of such energy production. They offer and reliable energy source with low CO2 emissions, though their development is limited to geologically suitable locations. Furthermore, some geothermal power plants incorporate CO2capture technologies, making them a cleaner and more sustainable alternative to fossil fuel-based power plants. Geothermal power plants harness the heat from the Earth's interior, which is generated by the natural decay of radioactive materials and the residual heat from the planet's formation. This thermal energy is stored in geothermal reservoirs, which are typically located in regions with significant tectonic activity, such as near volcanic zones and along plate boundaries. Reference is made to Figure 8, showing a schematic illustration of a geothermal powerplant 800 for energy production. The geothermal power plant 800 of Figure 8 extracts hot fluid803 from an underground geological reservoir 801 through a production well 802. At thegeothermal power plant 800, the extracted fluid 803 is separated in a separator 804 into twofluid streams 805, 806, one of steam 805 and one of separated water 806, such as brine. Inthe power plant 800, the steam 805 is used to drive turbines connected to generators (not illustrated), which convert the mechanical energy into electricity. The extracted fluid 803 from geological reservoirs 801 naturally comprises dissolved gases, including CO2, H2S, H2, N2, CH4, He etc. These gases are a by-product of the geothermal energy production. After energy production, it is desired that the steam 805 is condensed to a condensate 809 and reinjected into the geological reservoir 801, preferablywith the separated water 806, to sustain the geological reservoir 801. However, only a portionof the gases originally part of the extracted fluid re-condense with the steam, leaving the rest, so-called non-condensable gases, including CO2, as a gaseous by-product of the thermal energy production. These gases are normally removed from the condenser by vacuum pumps or ejectors and vented into the atmosphere. However, in the system illustrated in Figure 8, CO2 is not vented into the atmosphereafter power production. As can be seen in Figure 8, two pipes connect the power plant 800 to a scrubbing tower 811 (also referred to as an absorption tower). One pipe is configured for transporting the non-condensable geothermal gases 810, including CO2, to the scrubbing tower 811, whereas the other pipe is configured for transporting the condensate 809 to the scrubbing tower 811. The scrubbing tower 811 is configured for absorption of some of the non- condensable geothermal gases, including CO2, into the condensate 809, or any other water stream, under certain conditions, such that a gas-charged condensate comprising dissolved CO2 can be obtained. When CO2 is absorbed into the condensate 809 in the scrubbing tower 811, CO2 is dissolved in the condensate 809 and a portion of the dissolved CO2 will react with water in the condensate 809 to form carbonic acid (H2CO3), which can further dissociate into bicarbonate (HCO3-) and carbonate ions (CO32−). At equilibrium, all the CO2 species (H2CO3, HCO3- and CO32−) coexist in the aqueous solution. The relative amounts of each CO2 species present, depend on the pH of the solution and the equilibrium constants for the reactions. The resultant gas-charged condensate 812 may also comprise other fluids, such as thenoble gas helium (He) and water. This gas-charged condensate 812 is then (re)injected intothe geological reservoir 801, e.g. together with the separated water 806, as an injectate 808,through an injection well 807 (also sometimes referred to as a reinjection well) extending down into the geological reservoir 801. As illustrated in Figure 8, the injectate 808 may further beenriched with CO2 from the surrounding air, by capturing CO2 e.g. in the separated water 806,using a direct air capture (DAC) system. The geological reservoir 801 may comprise a network of basaltic rock formations andfracture networks that are integral to the permeability of the geological reservoir 801. These fracture networks are filled with reservoir fluid, which mixes with the injectate when it entersthe geological reservoir 801. As the injectate 808 comprising CO2 is injected into the geologicalreservoir 801, it starts to flow through different flow paths within the geological reservoir. When CO32−comes into contact with minerals of the geological reservoir 801, such as divalent cations (e.g. Ca2+ / Mg2+ / Fe2+) present in reservoir rocks, the divalent cations binds with aqueous CO2 to form solid carbonate minerals (e.g. calcium carbonate, magnesium carbonate, or ferrous carbonate). (Ca, Mg, Fe)2++ CO32-= (Ca, Mg, Fe)CO3(aq) This process is known as mineralisation. The key advantage of carbon mineralisation is that sequestered CO2 is immobilised and cannot escape back to the atmosphere, thusreducing CO2 emission to the atmosphere and limiting global warming. In this way, CO2 fromthe extracted fluid 803 can be reinjected into the geological reservoir 801 and recaptured underground after power production at the geothermal power plant 800, such that less CO2 is emitted to the atmosphere as a byproduct of the power production. The present invention relates to a method for monitoring mineralisation of CO2 injectedinto a geological reservoir. In embodiment, the present invention relates to a method formonitoring mineralisation of CO2 injected into reservoir via. a system as describedabove with reference to Figure 8.According to the method of the present invention, CO2 mineralisation can be monitored by estimating the ratio of13C / 12C of CO2 and / or CO2 / noble gas and / or18O / 16O in the injectate and comparing it to an estimated ratio of13C / 12C and / or CO2 / noble gas and / or18O / 16O in a mixed fluid extracted from an extraction well at a predetermined distance from the injection well. When estimating the13C / 12C ratio of CO2 in the injectate and / or the CO2 to noble gasratio in the injectate, in accordance with an embodiment of the present invention, this may bedone by performing first measurements on a sample taken from the injectate. However, it may also be done by performing the first measurements on several samples, taken from a plurality of fluids which has been merged to form the injectate and then estimating the13C / 12C ratio ofCO2 in the injectate and / or the CO2 to noble gas ratio in the injectate, based on the combinedresults. The plurality of fluids may e.g. be the separated water 806 and the gas-charged condensate 812. When the amount of CO2and the13C / 12C ratio of CO2is estimated, all the inorganiccarbon of CO2, gaseous and dissolved, has to be counted in, irrespective of the speciation itis found in. As described above, dissolved CO2 may be on different forms i.e. CO2(aq), H2CO3(aq),HCO3(aq) or CO32-(aq). (This may also be referred to as dissolved inorganic carbon (DIC)). Thus, the total amount of CO2 in a fluid includes CO2(g) and / or DIC. However, it may not be necessaryto measure all forms of CO2 separately. What is actually measured may depend on the phaseof the fluid and in case the fluid is an aqueous solution, pH of the solution to be measured,because the pH controls how much of the dissolved CO2 is on the different forms: CO2(aq),H2CO3(aq), HCO3(aq)or CO32-(aq). Thus, if one form is measured and the pH is known, the totalamount of CO2 may be estimated. The different forms of CO2 can also be converted to CO2using various methods such as acid digestion and titration, which can then be quantified usinga variety of analyses (e.g. gas chromatography, infrared gas analysis, etc). Isotope ratios(13C / 12C) may be measured using a mass spectrometer.Examples The experiments of the following example were performed in a system as describedwith reference to Figure 8. However, instead of comprising one monitoring well, the systemcomprises a plurality of monitoring wells, located at different distances from the injection well807. The monitoring wells are arranged further and further away from the injection well 807, such that the extracted fluid from the wells comprises a decreasing ratio of injectate808 compared to background reservoir fluid.Geological site The site on which the following experiments were carried out is located at Iceland’s largest geothermal power plant, Hellisheiði. The project has been operational since 2014 and captures ~12,000 tonnes of CO2 and ~6,000 tonnes of H2S annually from the power plant gas stream by dissolution into water. Gas- charged fluids are then re-injected into the ~260°C geothermal reservoir where in-situ CO2mineralisation is known to occur within months of injection. The geothermal reservoir below Hellisheiði power plant is comprised of fractured andhydrothermally altered olivine tholeiitic basalts. Alternating sequences of sub-glacial hyaloclastites and inter-glacial lavas dominate until -1400 metres above sea level (masl), below which the base of the Hengill volcano is found. Near-vertical intrusions dissect horizontal lavas and hyaloclastites to within a few hundred metres of the surface across the reservoir. The emplacement of these intrusions created fracture networks that are integral to the permeability of the geothermal reservoir. The upper groundwater system is separated from the geothermal reservoir by a low permeability clay cap rock found between -400 and -600 masl. Alteration minerals found in the reservoir vary with temperature and therefore depth, with chlorite, epidote, prehnite, wollastonite, wairakite, albite, calcite, pyrite, pyrrhotite, quartz and sulfides all being recorded. The target CO2storage zone is in the chlorite-epidote alteration zone, with recorded temperatures of 220-280°C. CO2capture Hellisheiði power plant is fed by >44 two phase (steam and water) geothermal production wells from three main areas: Skarðsmýrarfjall, Reykjafell, and Hverahlíð. Thisgenerates 303 MWe of electricity for Iceland’s national grid and 200 MWth of hot water forReykjavik district heating system. Approximately 0.5% of the steam mass is comprised of non- condensable gases, mainly CO2 (63 vol%), H2S (21 vol%) and H2 (14 vol%), with the remaining 2 vol% N2, CH4 and Ar. This corresponds to an annual production of ~33,000 tonnes of CO2 and ~8,000 tonnes of H2S from the power plant. In order to reduce and eventually eliminate these emissions, CO2 and H2S are dissolved in water and re-injected into the geothermalreservoir where in-situ CO2 mineralisation is known to occur within months of injection.Gases are fed into the base of a scrubbing tower adjacent to the power plant where they dissolve into 20°C condensed steam sourced from the power plant turbines at a flow rateof 50-55 l / s and pressure of 6 bar-a.56% of the CO2 and 97% of the H2S that enters the tower is dissolved and captured, as disclosed for in EP4031267A1 (SIGFÚSSON et al), which is incorporated herein by reference in its entirety. The average dissolved gasconcentration of the gas-charged condensate leaving the scrubbing tower is 102 mM dissolvedinorganic carbon (DIC) and 73 mM dissolved sulfur (DS), with a solution pH of between 3.5and 4. Gas-charged condensate is then transported to the reinjection well HN-16 via a 1.5km long polyethylene pipe at 9 bar-a. CO2 injection HN-16 is a 1.9km deep water re-injection well within the Húsmúli reinjection zone of Hellisheiði geothermal field. The five reinjection wells at Húsmúli (including HN-16) accountfor ~10 Mt of the ~28 Mt of separated water and condensate annually reinjected at Hellisheiði.HN-16 and HN-14 (the back-up CO2injection well) have been retrofitted with a 750m long 4”stainless steel pipe within the existing carbon steel casing that extends for 660m. This is toprotect the steel casing from the corrosive (pH 3.5-4) gas-charged condensate, which isinjected via this stainless steel pipe at 30-60 l / s. These fluids take two to four minutes to reachthe bottom of this piping where they then mix with power plant separated water and is co-injected as an injectate via the carbon steel casing at a rate of 15-130 l / s (Clark et al., 2020).These waters are 55-140°C, have a pH of 6-9.1 and a DIC concentration of 0.4-1.5 mM. Clark et al., (2018) modelled the downhole mix of gas-charged condensate and power plant separated water on the flow rates reported in Sigfússon et al., (2018). They report a 70% 80°C separated water and 30% 20°C gas-charged condensate mix, with a pH of 5.4, DIC of 31 mM and DS of 22 mM before the tower scale up in July 2016, and a pH of 4.7, DIC of 51 mM and DS of 31 mM after this period. This mixture takes 10-45 minutes to reach the main feedzones in HN-16 which are located between -700 and -1600 masl. These highly permeable zones were identified during the drilling of geothermal wells and relate to fracture networks thatdeveloped during intrusion emplacement and regional tectonic movements. The injectate isdenser than surrounding reservoir fluids (0.95-0.99 g / cm3 vs.0.78-0.84 g / cm3) because of itslower temperature and dissolved gas content. This means that the injectate sink once in thereservoir, which ensures solubility trapping for injected CO2 and lengthens fluid flow pathways. Longer flow pathways increase the water-rock interactions that are integral to in-situ CO2mineralisation and reduce the risk of thermal breakthrough from cold injectate in nearbyproduction wells which would result in a depletion of the geothermal resource. Monitoring and verification The fate of injected CO2 (and H2S) is observed via four monitoring wells that are down- flow from injection well HN-16. Subsurface fluid flow from the Húsmúli reinjection zone is towards the Skarðsmýrarfjall production area to the northeast. This is due to NE-SW trending fractures associated with the regional and the pressure gradient created from ~10 Mt / year fluid production from six wells (HE-31, HE-48, HE-44, HE-33, HE-05 and HE-08). HE- 31, HE-48, HE-44 and HE-33 are used as monitoring wells in Carbfix. These wells are 1000- 1500m from HN-16, 1400-2350m deep and have feedzones between -300 and -1600 masl. The relative proportions of injected and background reservoir fluids in each monitoring well are known from a series of non-reactive tracer tests conducted in the Húsmúli reinjection wells (Kristjansson et al., 2016; Ratouis et al., 2022). For the purposes of this study, we refer to the results of the continuous tracer testconducted from July 2014 to July 2015, where 274kg of the inert tracer 1-naphthalenesulfonic acid sodium salt (1-ns) was co-injected with gas-charged condensate at a constant proportioninto the injection well HN-16 (Ratouis et al., 2022). Tracer recovery rates are disclosed in Table1. Both tracer tests indicated fast flowing pathways consistent with fluids flowing through a fracture system (Ratouis et al., 2022). As expected, the wells closest to the injection well (HE- 31 and HE-48) experience quicker tracer breakthrough periods and recover the higher proportions of tracer compared to wells further from HN-16 (HE-44 and HE-33). Table 1: Results of the 2014-2015 continuous tracer test from the Carbfix injection wellHN-16. 274kg of thermally stable 1-ns tracer was co-injected with Carbfix gas-chargedcondensate at a constant ratio to determine fluid flow paths, rates, and background mixing ratios in monitoring wells. Data are from Ratouis et al., (2022). First arrival Recovery Background mixing ratioHE-31 14 days 22% 75%HE-48 29 days 22% 77%HE-44 79 days 8% 90%HE-33 456 days 2% 97%The co-injection of inert tracer with gas-charged condensate enabled a comparison of non-reactive (1-ns) tracer and reactive (DIC and DS) tracer recovery rates in the monitoring wells to determine the proportion of injected CO2 and H2S retained and mineralised within the reservoir. To date, there have been two publications that quantify the extent and time frame of CO2 mineralisation in the reservoir. Gunnarsson et al., (2018) reported that >50% of injected CO2 and 76% of injected H2S mineralised between injection well HN-16 and the first monitoring well HE-31 within 4-9 months of injection. These figures were updated by Clark et al., (2020) who found that >60% of injected CO2 and >85% of injected H2S within four months of injection. This increase was attributed to the doubling of the scrubbing tower capacity in July 2016 andthe subsequent decrease in injectate pH.Both studies report that the injectivity of HN-16 has remained stable throughout, indicating that the permeability of the reservoir has been unaffected by mineralisation. Materials and Methods Sample collection Liquid and gas samples were collected from across the study area. Samples were collected from production and / or monitoring wells, and from the injectate. Wells Geothermal production wells HE-03 and HE-07 in Hellisheiði, and HE-54 and HE-60 in Hverahlíð were sampled, along with monitoring wells HE-31, HE-48, HE-44, and HE-33. Monitoring wells are also active production wells that feed back into Hellisheiði geothermal power station. Figure 1 shows a schematic diagram of a phase separation system 101 for a fluidproduced from a monitoring well, according to an embodiment. The system 101 was purged for five minutes prior to sample collection. As shown in Figure 1, the well 110, is equipped with a wellhead 111, are wet-steam wells. The single phase is flashed through a pressure control valve 112 near the wellhead111, thereby producing a mixture of water 121 and steam 122. These two phases werecollected separately using a Webre separator 120 at the wellhead 111. The system 101 alsocomprises a first and cooling coil 131 to cool the water phase 121, and a second cooling coil 132 to cool the steam phase 122. The cooled water phase is collected as water samples 121a The second cooling coil is associated with a second separator 125 which results in thesteam 122 condensing to form a liquid condensate 123, which is then collected into 60μlNalgene bottles, and also produces a third phase 124 comprised of non-condensable gases which contains in particular noble gases and CO2 isotopes. These samples were collected in 3 / 8” refrigeration grade copper tubes. Atmospheric back-flow and contamination was prevented by connecting the end of the copper tube to hosing that was placed in a bucket of water. As with water samples 121a, the copper tubes were purged for five minutes prior to sample collection. Tubes were sealed using two steel clamps specifically designed to provide a cold weld seal and prevent helium leakage. The clamp furthest from the wellhead was sealed first to ensure no contamination from atmosphere. In other words, Figure 1 shows how a fluid sample extracted from an extraction well is separated into three different phases, before measurements are performed on the different phases of the extracted fluid sample by measuring the amount of12C and13C of CO2,3He,18Oand 16O in the phases. Abundance fractions for compounds water, CO2, noble gases) are as follows for each sample 124, 123, 121a shown in Figure 1:. Non-condensable gases (g) 124:Noble gases f=>99%CO2 f=~99% H2O f=0% Steam condensate (s) 123:Noble gases f=<1% CO2f=~<1% H2O f=18% Water (w) 121a: Noble gases f=CO2f=~8% H2O f= 82%Data generated from these three phases (water, steam, and non-condensable gas) are then combined to correct for the wellhead separation process and provide the total well dischargei.e. to estimate a 13C / 12C ratio of CO2 and / or the CO2 to 3He ratio and / or the 18O / 16O ratio ofwater in the extracted fluid sample. Injectate In this experiment, the injectate was provided by contacting the steam condensate and the non-condensable geothermal gases obtained from the geothermal power plant in ascrubbing tower to form a gas-charged condensate. The gas-charged condensate was thenmerged with the separated water obtained from the geothermal power plant.To estimate the13C / 12C ratio of CO2, the CO2 to3He ratio and the18O / 16O ratio of water in the injectate, samples of the power plant non-condensable gases were collected from the inlet and outlet (geothermal gas and gas-charged condensate) gas pipelines of the Carbfix scrubbing tower using the copper tube method described above. Sampling apparatus were connected directly into the gas lines and therefore did not require a separator or funnel for collection. Water samples of the steam condensate used for gas dissolution in the Carbfixscrubbing tower, and the power plant separated water which was co-injected with the Carbfixgas-charged condensate, were collected from before the Carbfix scrubbing tower and injectionwell respectively. Data generated from these samples are then combined to calculate thegeochemical fingerprint of the Carbfix to estimate the ratio of 13C / 12C of CO2, theCO2 to3He ratio and the ratio of18O / 16O of water in the injectate. Geochemical analyses All geochemical analyses were undertaken at the Scottish Universities Environmental Research Centre (SUERC) in East Kilbride, Scotland. Copper tubes were halved using an additional steel clamp in the middle of the tube to allow for separate noble gas and CO2 isotope analysis. Noble gas measurements Copper tubes were connected to an all-metal ultra-high vacuum system and prepared for analysis. The concentration and isotopic composition of noble gases were measured on an MAP 215-50 noble gas mass spectrometer. Mass fractionation, sensitivity and the reproducibility of analyses were determined by repeated analysis of HESJ international standard (for He and air for Ne). Reproducibility of noble gas concentrations and isotope ratios were typically better than 5%. 3He / 4He reporting and corrections Measured3He / 4He ratios (RM) are reported relative to the atmosphere3He / 4He (RA= 1.4 x 10-6) and corrected for air contamination (Rc) using the method outlined in Füri et al.,(2010) and Hilton et al., (1996):^^^^^^^^ (Equation 1)where^^is the air corrected3He / 4He reported rel3 4 ^^^^ative to He / He of atmosphere,^^is themeasured 3He / 4He reported relative to 3He / 4He of atmosphere, and ^^ corresponds to: (Equation 2)where ^^ is the Bunsen coefficient of 1.25 at the ambient temperature of 10°C (Füri et al., 2010;Byrne et al., 2021). Gas chromatography (GC) measurements Bulk gas concentrations of copper samples were measured using a Pfeiffer Vacuum QMS 200 quadrupole mass spectrometer and Hewlett Packard 5890 Series 11 Gas Chromatograph with uncertainties of ± 1%. Major gas concentrations are corrected for air. Isotope ratio measurements Ratios of stable isotopes in the constituent elements of CO2 and H2O were measured in the gas and liquid samples respectively. Data are reported as delta (δ) values per mil (‰), meaning parts per thousand difference relative to international reference standards: ^^ ^^^^^^^^^^^^^^^^^^ ^^^^^^^^ (Equation 3) sample isotope value and ^^ corresponds to the isotoperatio (13C / 12C,18O / 16O and2H / 1H) for the sample and standard. Carbon isotope ratios Ratios of stable carbon (13C / 12C) isotopes of CO2 in the copper tube samples weremeasured on a VG SIRA II Dual Inlet Isotope Ratio Mass Spectrometer using an internal standard produced from international reference materials NBS19 and IAEA-CO-1. Isotope data are reported relative to international reference standard Vee Pee Dee Belemnite (VPDB), with 1σ uncertainties of ± 0.1‰. Water isotope ratios Ratios of stable oxygen (18O / 16O) and hydrogen (2H / 1H) isotopes in H2O were measured using standard automated techniques on a Thermo Scientific Delta V mass spectrometer set at 25°C. Isotope data were produced using the method established by Nelson (2000) and are reported relative to international reference standard VSMOW with 1σ uncertainties of ± 0.3‰ for δ18O and ± 3‰ for δ2H. Calculations Re-equilibration of multi-phase samples As described above, the fluid samples obtained from extraction wells analysed in this study have multiple phases that need to be combined and re-equilibrated to attain the total extraction well discharge. The calculation required for re-equilibration is dependent on how noble gases, CO2and H2O partition between the three phases (water, steam, and non- condensable gas). This in turn is controlled by the temperature, pressure, and pH of phase separation, all of which are measured at the separator during sampling. Noble gases Noble gases are chemically inert and insoluble in water, meaning they preferentially partition into gaseous phases during phase separation. As noble gas measurements are takenfrom the non-condensable gas phase, we assume this phase is representative of the total welldischarge and no re-equilibration is needed for these data.CO2 / 3HeThe partitioning of CO2 between steam and water phases in the Carbfix monitoring wells isreported in the supplementary materials of Clark et al., (2020). They report ~92% of CO2partitions into the steam phase and the remaining ~8% remains dissolved in the water phase.We use this to calculate the partitioning of CO2and3He between steam and water phases, using dimensionless Henry’s constants and the vapour-liquid distribution coefficientsof Fernández-Prini et al., (2003) at the separation temperature (180°C) pressure (9 bar) andsalinity (0.05 M / L). This indicates that >99% of3He partitions into the steam phase, as expected given the insolubility of noble gases, and as a result pre-separation CO2 / 3He are within uncertainty limits of CO2 / 3He measured in the non-condensable gas samples. Given this, we use these measured values as the equilibrated values for total well discharge. CO2 and H2O isotopesPartitioning of the constituent isotopes of CO2 and H2O between steam condensate and separated water phases can be corrected for to acquire total well isotope ratios using the following equation: ^^^^^^ == ^^^^ × ^^^^ + (^^ − ^^^^) × ^^^^ (Equation 4)where ^^ is the δ13CCO2 δ18OH2O or δ2HH2O value of the total discharge (^^^^), vapour phase (^^)and liquid phase (^^), and ^^^is the fraction of CO2 or H2O present in the vapour phase. For δ13CCO2, the vapour and liquid phases correspond to gaseous CO2 measured in the non- condensable gas and DIC measured in the separated water. For δ18OH2O and δ2HH2O vapour and liquid phases correspond to the steam condensate and separated water samples. CO2^^^is derived using the timeseries data of Clark et al., (2020). H2O ^^^is calculated using themeasured wellhead enthalpy, pressure and separation temperature (Saby et al., 2020).Results Noble gas concentrations and ratios are reported in Table 2. GC (gas chromatography)CO2 / 3H, CO2 and H2O isotope data are reported in Table 3.Noble gas ratios3He / 4He Air corrected 3He / 4He ratios (RC / RA) range from 14.3 (± 0.9) to 16.6 (± 2.0). Hellisheiðiand Hverahlíð production wells range between 14.9 (± 0.8) and 16.6 (± 2.0). Carbfix scrubbingtower gas outlet (14.8 ± 0.9) and inlet (14.3 ± 0.9) are within error of each other. v monitoringwells are also within uncertainty of each other, ranging from 14.7 (± 0.8) in HE-33 to 15.9 (±0.9) in HE-48. 4He / 20Ne Measured4He / 20Ne ratios range from 2.8 (± 0.1) to 34.6 (± 1.8). Hellisheiði andHverahlíð production wells range between 3.0 (± 0.1) and 19.1 (± 1.0). Carbfix scrubbing towergas outlet (3.6 ± 0.2) is higher than the gas inlet (2.8 ± 0.1). Carbfix monitoring wells rangefrom 25.6 (± 1.1) in HE-48 to 34.6 (± 1.8) in HE-44. GC Copper tube samples contained 59-95% CO2. No H2S was not measured in any of the samples despite it being the second largest non-condensable gas by volume produced at Hellisheiði geothermal power plant. H2S rapidly reacts with the internal surface of the copper tubes once sealed during sampling, forming copper sulphate, and removing it from the gas mix. Although this alters individual gas percentage values, gas concentrations relative to each other remain the same, meaning ratios (3He / 4He;4He / 20Ne; CO2 / 3He) are unaffected. CO2 / 3He CO2 / 3He varies by an order of magnitude from 1.4 x 109(± 1.1 x 108) to 1.4 x 1010(± 1.1 x 109). Hellisheiði and Hverahlíð production wells range between 3.0 x 109(± 2.4 x 108) to6.9 x 109 (± 5.8 x 108). Carbfix scrubbing tower gas outlet (3.2 x 109 ± 2.6 x 108) is 50% lowerthan the gas inlet (6.4 x 109 ± 5.1 x 108). Carbfix monitoring wells range from 1.4 x 109 (± 1.1x 108) in HE-44 to 2.0 x 109(± 1.6 x 108) in HE-31. Carbon isotope ratios Results described below refer to equilibrated total discharge values, rather than CO2(g) or DIC data. All phases are reported in Table 3. δ13C δ13CCO2 values range from -6.6‰ to -2.8‰ VPDB. Hellisheiði and Hverahlíð production wells range between -6.6‰ and -3.2‰. HE-60 (-6.6‰) is an outlier of the dataset, with thenext lowest measured value being -3.9‰ in the Carbfix scrubbing tower gas inlet. The scrubbing tower gas outlet (-2.8‰) is the gas inlet (-3.9‰). Carbfix monitoring wells range from -3.6‰ in HE-33 to -3.4‰ in HE-31. Water isotope ratios Results described below refer to equilibrated total discharge values, rather than steam condensate or separated water phases. All phases are reported in Table 3. δ18O δ18OH2Ovalues range from -8.7‰ to -0.6‰ VSMOW. Hellisheiði and Hverahlíðproduction wells range between -8.3‰ and -6.9‰. Carbfix monitoring wells range from -8.6‰in HE-33 to -7.6‰ in HE-48. δ2H δ2HH2O values range from -73.4‰ to -46.3‰ VSMOW. Hellisheiði and Hverahlíðproduction wells range between -73.4‰ and -64.9‰. Carbfix monitoring wells range from -69.8‰ in HE-48 to -67.3‰ in HE-44.

[0002] Table 2: Concentrations and ratios of gases contained within non-condensable gas samples collected in copper tubes at Hellisheiði. Measured3He / 4He ratios (RM) and atmosphere corrected ratios (RC) are reported relative to atmosphere (RA= 1.4 x 10-6). Air correction is calculated usingthe method outlined in Füri et al., (2010) and Hilton et al., (1996). Uncertainties are one standard deviation (1σ).Samples Noble gases (cm3 / cm3 STP) Noble gas ratiosSystem LocationSampling3He ± d 4He ± d 20Ne 3 4 4 20point± d He / He (R / RA) ± d He / Ne ± d X ± d RC / RA ± dFumarole 6.2E-11 4.1E-12 3.2E-06 9.6E-08 9.1E-07 3.2E-08 13.8 0.5 3.5 0.2 13.9 0.6 14.8 0.9HverahliðHE-54 1.8E-10 1.2E-11 7.8E-06 2.4E-07 5.4E-07 6.1E-08 16.4 0.6 14.4 1.7 56.8 6.6 16.6 2.0Geothermal fieldHE-60 8.5E-11 5.7E-12 4.5E-06 1.3E-07 1.5E-06 3.7E-08 13.8 0.5 3.0 0.1 11.8 0.5 14.9 0.8HE-03 2.9E-10 1.9E-11 1.3E-05 4.0E-07 7.0E-07 2.9E-08 15.6 0.6 19.1 1.0 74.9 3.8 15.8 1.0Hellisheiði HE-07 2.0E-10 1.4E-11 1.0E-05 3.0E-07 1.6E-06 6.8E-08 14.4 0.5 6.2 0.3 24.4 1.2 15.0 1.0ScrubbingInlet 1.3E-10 8.5E-12 6.9E-06 2.1E-07 2.4E-06 9.9E-08 13.1 0.5 2.8 0.1 11.2 0.6 14.3 0.9tower gasesOutlet 2.3E-10 1.5E-11 1.2E-05 3.5E-07 3.3E-06 1.4E-07 13.8 0.5 3.6 0.2 14.0 0.7 14.8 0.9HE-31 4.6E-10 3.3E-11 2.3E-05 6.7E-07 7.4E-07 3.7E-08 14.9 0.6 30.4 1.8 119.5 7.1 15.0 1.1Carbfix MonitoringHE-48 5.1E-10 3.4E-11 2.3E-05 6.9E-07 9.1E-07 2.7E-08 15.7 0.6 25.6 1.1 100.8 4.2 15.9 0.9wellsHE-44 6.7E-10 4.6E-11 3.3E-05 9.7E-07 9.4E-07 3.9E-08 14.9 0.6 34.6 1.8 136.0 6.9 15.0 1.0HE-33 5.1E-10 3.4E-11 2.5E-05 7.5E-07 7.8E-07 2.2E-08 14.6 0.5 32.3 1.3 126.9 5.2 14.7 0.8

[0003] Table 3: Elemental abundances, CO2 / 3He and stable isotope ratios measured in gas and water samples from Hellisheiði. GC and CO2(g)isotope measurements were taken from non-condensable gas samples collected in copper tubes. DIC isotope measurements were made separated water samples for production and monitoring wells. ‘l / c’ corresponds to low concentration of DIC which resulted in unreliable δ13C data. H2O isotope measurements for wells were taken from separated water and steam condensate samples. The fractionation induced on CO2and H2O isotopes during the phase separation process is corrected for using Equation 3 to produce equilibrated (total) values. The fumarole and injection fluids samples only have one phase; therefore, they do not require re-equilibration.1σ uncertainties for δ13C, δ18O and δ2H are 0.1‰, 0.3‰ and 3.0‰ respectively. Samples GC (% volume)CO2 H2O CO2 / 3He ± d δ13C (‰) VPDB δ18O (‰) VSMOW δD (‰) VSMOWSystem Location Sampling point CO2 H2S N2 CH4CO2(g) DIC Total Steam Water Total Steam Water TotalFumarole 87% 0% 13% 0% 1.4E+10 1.1E+09 -3.7 l / c -3.7 n / a n / a -0.6 n / a n / a -46.3HverahliðHE-54 95% 0% 5% 0% 5.4E+09 4.2E+08 -3.2 l / c -3.2 -8.6 -6.7 -8.0 -73.8 -72.7 -73.4Geothermal fieldHE-60 59% 0% 41% 1% 6.9E+09 5.8E+08 -6.6 l / c -6.6 -8.4 -6.3 -8.3 -71.0 -67.7 -70.8HE-03 86% 0% 13% 1% 3.0E+09 2.4E+08 -3.6 l / c -3.6 -8.9 -6.4 -7.1 -68.4 -63.5 -64.9Hellisheiði HE-07 93% 0% 5% 2% 4.6E+09 3.6E+08 -3.4 l / c -3.4 -8.7 -5.9 -6.9 -70.0 -64.1 -66.2ScrubbingInlet 80% 0% 18% 1% 6.4E+09 5.1E+08 -3.9 n / a n / a n / a n / a n / a n / a n / a n / atower gasesOutlet 73% 0% 27% 1% 3.2E+09 2.6E+08 -2.8 n / a n / a n / a n / a n / a n / a n / a n / aInjectionSeparated water n / a n / a n / a n / a n / a n / a n / a l / c n / a n / a -6.0 n / a n / a -62.5 n / afluids CarbfixSteam condensate n / a n / a n / a n / a n / a n / a n / a l / c n / a -8.7 n / a n / a -67.5 n / a n / aHE-31 94% 0% 6% 0% 2.0E+09 1.6E+08 -3.2 -5.6 -3.4 -10.1 -7.4 -7.9 -73.0 -67.1 -68.2MonitoringHE-48 93% 0% 6% 0% 1.8E+09 1.4E+08 -3.3 -5.3 -3.5 -8.2 -7.5 -7.6 -69.0 -70.0 -69.8wellsHE-44 93% 0% 7% 0% 1.4E+09 1.1E+08 -3.4 -5.4 -3.6 -10.4 -7.7 -8.2 -73.0 -66.0 -67.3HE-33 94% 0% 6% 0% 1.8E+09 1.4E+08 -3.5 -5.1 -3.6 -10.9 -8.1 -8.6 -74.4 -68.1 -69.2

[0004] Discussion Regional context of results Noble gas, CO2 and H2O isotope data collected from Hellisheiði geothermal fieldand power plant are all within ranges previously recorded in published literature for theWVZ of Iceland. They indicate a magmatic source of gases (CO2 and He), meteoricsource of fluids and varying extents of meteoric fluid mixing and gas-water-rockreactions. Noble gas ratios 3He / 4He and 4He / 20Ne values (see Table 2) fall within the range previouslyrecorded for the western rift zone (WRZ) of Iceland (see Figure 2) (Harðardóttir et al.,2018) and are similar to previous data from Hengill (Füri et al., 2010). When plottedtogether with 3He / 4He, data indicate two-part mixing between a high and low R / RA and4He / 20Ne source. Meteoric fluids are the low source because they are equilibrated withatmospheric noble gases (e.g., 20Ne), and therefore have RA and 4He / 20Ne values of 1and 0.318 respectively (Benson and Krause, 1980; Smith and Kennedy, 1983; Ballentine and O’Nions, 1994; Saby et al., 2020). We derive the high RAand4He / 20Ne source using an inverse mixing hyperbola calculation as described in Albarède, (1996) and Saby et al., (2020). This gives a local mantle value of 15.1 R / RA (Figure 2), which suggests mixing between an Icelandic plume (R / RA = >35) and depleted mid-ocean ridge (MORB) type mantle (DMM) source (R / RA = 8). The extent of mixing and dilution of magmatic and meteoric noble gases is likely dependent on the specific hydrogeology of a given well, as demonstrated by differing RAand4He / 20Ne values for wells from the same production area (HE-03 vs. HE-07 and HE-54 vs. HE-60 on Figure 2).CO2 / 3He CO2 / 3He values (see Table 2) fall within the magmatic range of 109 to 1010 (Martyand Jambon, 1987; Trull et al., 1993; Ballentine et al., 2001; Holland and Gilfillan, 2013)and overlap with previous data from Hengill (Barry et al., 2014). The Carbfix scrubbingtower gas inlet sample, which is an average CO2 / 3He for Hellisheiði production wells, iswithin the uncertainty ranges of previously published averages for Hengill (5 x 109) andthe Icelandic plume (6 x 109). δ13C δ13CCO2 values also overlap with literature averages for Hengill (-4.1‰ VPDB)and the Icelandic plume (-3.8‰) (Figure 3). The Carbfix gas inlet (-3.9‰ ± 0.1 VPDB) iswithin measurement uncertainty of the plume average, and all data points plot within 1‰of this average, apart from Hverahlíð production well HE-60.H2O isotopes Water isotope data overlap with previous results from Hellisheiði (Mutonga 2007)and are characterised by two trends: enrichment in18O relative to meteoric water and δ18O-δ2H correlation that differs from the meteoric water lines (Figure 4). 18O enrichment In high temperature geothermal systems such as Hellisheiði, isotope exchange occurs between reservoir fluids and oxygen-baring minerals in host rocks. Depending on the water-rock ratio, this can buffer δ18OH2Otowards the rock value, with lower water-rock ratios resulting in larger shifts in δ18OH2O. MORB basalts have average δ18O values of ~+5‰ VSMOW, and analysis of rocks from Hellisheiði and the Hengill fissure swarm record similar values. Waters in Hellisheiði geothermal reservoir will therefore become progressively enriched in18O over time as they are buffered towards the rock value of ~+5‰ VSMOW. The recent study of Wostbrock et al., (2018) used a triple oxygen isotope mixing model to calculate that production waters at Hellisheiði are 20% altered by high temperature oxygen isotope exchange with geothermal host rocks. This partially explains why data in this study record higher δ18OH2Ovalues than local meteoric water. δ18O and δ2H correlation As well as higher δ18O values than meteoric water, H2O isotope data show a clearpositive correlation that differs from the global and local meteoric waters (see Figure 4).One of the causes of this trend is the fractionation of O and H isotopes during separation of the single-phase geothermal fluid into steam and water phases. Heavier18O and2H are preferentially retained in the separated water phase, leading to lower steam condensate and higher separated water δ18O and δ2H values relative to the total discharge. This means the difference in power plant steam condensate and separated water δ18O and δ2H values equates to the ^^^^^^^^^^^^^at the temperature of phase separation. We can back-calculate this difference using the equilibrium fractionation equations of Horita and Wesolowski (1994) to acquire temperature of phase separation. δ18OH2O ^^^^^^^^^^^^^of 2.5‰ returns a separation temperature of 191-195°C, and δ2H^^^^^^^^^^^^^ of 5.4‰ returns 187°C. Separation temperatures during sampling of thewells reported in this study varied from 176°C to 210°C, which encompasses the isotope- derived temperatures above. An additional potential cause of δ18O and δ2H correlation is the mixing of differingfluid sources. Previous water isotope studies of Hellisheiði and sister geothermal fieldNesjavellir concluded that the two fields do not share the same source of water, despitetheir positioning on either side of the Hengill volcanic centre. Hellisheiði was interpretedto be fed by local meteoric waters that were enriched in2H relative to the inland highland- sourced2H-depleted waters that fed Nesjavellir. In these previous studies, it was alsonoted that certain wells on the periphery of Hellisheiði recorded lower δ2HH2O, and it wassuggested that this was caused by a mixing of local Hellisheiði meteoric water with theisotopically lighter fluids that feed Nesjavellir. We believe our results support this hypothesis. Production wells HE-03 and HE-07 plot in a similar oxygen and hydrogen isotopespace to the previous data of Mutonga (2007) (Figure 4), whereas Carbfix monitoringand Hverahlíð production wells are relatively depleted in 18O and 2H. Carbfix monitoringwells are the most northerly production wells at Hellisheiði, meaning they aregeographically the closest Hellisheiði wells to Nesjavellir. Given this, the monitoring wellsare more likely than other production wells to record water isotope values similar toNesjavellir data. Alinear regression of H2O isotope data in this study (excluding the power plantsamples) intersects the meteoric water lines at a similar point to the source watersproposed for Nesjavellir (Figure 4). This suggests there is some mixing of Nesjavellir-type waters in certain wells, such as the Carbfix monitoring wells, as was previouslyproposed by. Ongoing CO2 injection at Carbfix is not thought to contribute to δ18OH2Ovalues because it comprises an insignificant portion of the overall oxygen isotope pool (<1%; Sigfússon et al., 2018). Carbfix scrubbing towerQuantifying CO2 dissolution The scrubbing tower has two inputs (gas inlet – geothermal gas) and purecondensate) and two outputs (gas outlet –remaining non-condensable gases) and gas-charged condensate), and operates at fixed conditions of 20°C and 6 bar. This means the tower is a closed geochemical at controlled conditions, therefore changes between inputs and outputs will isotopically balance. We assume changes inCO2 / 3He are indicative of CO2 behaviour because 3He is insoluble relative to CO2 at towerconditions and the steam condensate is not a source of3He. This means shifts in CO2 / 3He between inlet and outlet samples can be used to calculate the fraction of CO2 dissolved in the tower: (Equation 5) where subscripts (^^) and (^^) are the measured CO2 / 3He of the gas inlet and outlet respectively. This indicates 50% (± 4%) of CO2 was dissolved in the scrubbing tower at the time of sampling, which is similar to the 56% dissolution reported in Gunnarsson et al., (2018) (no uncertainty range was reported). Isotope fractionation The fractionation factor (^^) for δ13CCO2 during CO2 dissolution can be calculated using the remaining fraction (^^) of undissolved CO2 and a rearranged version of the Rayleigh fractionation equation (Mariotti et al., 1981; Clark and Fritz, 1997; Hayes, 2004): ^^ (Equation 6)where ^^ is the carbon isotope value of CO2. This results in a ^^^^^(^^)^^^^(^) value of -1.6‰ (± 0.2). Studies of Vogel et al., (1970) and Zhang et al., (1995) report equilibrium ^^^^^(^^)^^^^(^)of -1.1‰ and -1.2‰ respectively for 20°C, suggesting more12C is beingdissolved relative to 13C in the Carbfix scrubbing tower than would be expected atequilibrium conditions. Carbon isotope equilibrium between CO2 and DIC is usually established within hours, therefore if dissolution is proceeding faster than this timescale in the scrubbing tower, this may explain the discrepancy between CO2 / 3He-derived ^^^^^(^^)^^^^(^)of this study and literature equilibrium values (Myrttinen et al., 2015). Calculating injectate values Dissolved gases We can use the shifts between gas inlet and outlet CO2 / 3He and δ13CCO2 to calculate values for the dissolved CO2. CO2 / 3He Changes in CO2 / 3He between the gas inlet and outlet (geothermal gas and gas- charged condensate) will mass balance with respect to the dissolved CO2. As dissolution progresses, the CO2 / 3He of dissolved CO2 increases and can be calculated using the following equation: (Equation 7) CO2 / 3He of dissolved CO2. This producesan estimated CO2 / 3He ratio for dissolved CO2 of 9.6 x 109 (± 8.9 x 108) (Table 3 andFigure 5). δ13C Changes in δ13CCO2 between gas inlet and outlet samples will also mass balance with respect to dissolved CO2. For the tower system we use an isotope mass balance equation for an accumulated reaction product (Clark and Fritz, 1997): ^^ ^^(Equation 8) where ^^ is the δ13C of the dissolved (^^) and gas outlet (^^) CO2, ^^^^^(^^)^^^^(^) isthe isotope fractionation factor calculated for δ13C above, and ^^ is the remainingundissolved CO2. The estimated δ13CCO2 value produced from this is -5.0‰ (± 0.2‰)VPDB (Table 3 and Figure 5). The accumulated product equation is used rather than the instantaneous equation because (1) gas charged condensate accumulates at the bottom of thescrubbing tower and (2) all dissolved CO2 is injected into the Carbfix storage reservoir.This means on a reservoir scale the overall isotope value of injected dissolved CO2will equate to the accumulated product value. While this is likely a simplification of the truesystematics of CO2 dissolution in the Carbfix scrubbing tower, particularly from a singlesample set such as in this study, we believe it the most representative isotopefractionation model for the Carbfix injectate.

[0005] Injected fluids Injectate δ18O and δ2H values will be controlled by the mixing ratio between the gas charged condensate and co-injected separated water. Dissolution of CO2into steam condensate does not influence the δ18OH2O of the gas charged condensate because data from Sigfússon et al., (2018) indicate CO2 constitutes <1% of the total overall oxygenisotope pool post-dissolution. As a result, the δ18O and δ2H of the Carbfix injectate canbe calculated using a modified version of Equation 4: ^^^^^^ = ^^^^^^ × ^^^^^^ + − × ^^^^^^ (Equation 9) of the Carbfix injectate (^^^^), gas-chargedcondensate (^^^^) and re-injected separated water (^^^^), and ^^^^^^is the fraction of the injectate water that is sourced from the gas charged condensate (0.3; from Clark et al., 2018). This results in injectate δ18OH2O and δ2HH2O values of -6.8‰ (± 0.4‰) and -64.0‰ (± 4.2‰) VSMOW: Table 4: Summary of calculated Carbfix injectate isotope valuesδ13CCO2 (‰) δ18 2CO2 / 3He OH2O (‰) δ HH2O (‰) VPDB VSMOW VSMOW Carbfix 9.6 x 109(± 8.9 x injectate 108)-5.0 (± 0.2) -6.8 (± 0.4) -64.0 (± 4.2)Carbfix CO2 mineral storage reservoirWe now compare the injectate values calculated above to measured data inCarbfix monitoring wells HE-31, HE-48, HE-44, and HE-33 to evaluate the fate of injectedCO2 in the storage reservoir. The key difference between the Carbfix scrubbing towerand mineralisation reservoir systems is the presence of background fluids and CO2. The majority of fluids and gases produced in the monitoring wells are background and do notoriginate from the Carbfix injection (see Table 1). This means injectate signals and anymineralisation-related isotope shifts will only be seen in monitoring wells if these values are distinct from background, even after they are diluted by mixing. This is particularly relevant for mineralisation effects because as CO2 is removed the remaining fractionated CO2 comprises an ever-smaller portion of the monitored DIC pool, thus increasingly the likelihood of overprinting from background signals. Baseline scenario: injectate- mixing with no mineralisation It is first sensible to assess the shifts that would be expected in monitoring well isotope values if no mineralisation occurred in the reservoir and wells produced an injectate-background mix only. Previous non-reactive tracer testing of background fluidmixing in the Carbfix reservoir informs us on the likely proportion of injectate andbackground fluids in each monitoring well (Table 1). These data were acquired four years prior to our sampling campaign, so the use of these data assumes background mixing ratios have remained stable through time. To model injectate-background mixing we also need isotope values for background fluids in the reservoir. Ideally this would be provided from pre-injection baseline data, but we do not have such a dataset. In the absence of this, we use data measured in HE-33 as the geochemical fingerprint of background fluids and CO2in the Carbfix reservoir. HE-33 recovered <3% of the tracers injected in the 2014 tests (Table 1), meaning it is >97% background fluids. The use of HE-33 as background assumes that all monitoring wells share isotopically similar background fluids and CO2. According to Table 3, monitoring well HE-33 has a δ13CCO2(‰) VPDB of -3.6. Thus, the background level of δ13CCO2(‰) VPDB in the geothermal reservoir is -3.6. According to table 4, the injectate level of δ13CCO2(‰) VPDB is -5 and the injectateCO2 / 3He ratio is 9.6 x 109.Using these data, as well as the background mixing ratios of Table 1 and the DICconcentrations of the Carbfix injectate (50.6 mM; Clark et al., 2020) and background DIC(8.36 mM; Gunnarsson et al., 2018), we can predict an expected δ13CCO2 (‰) VPDB andCO2 / 3He ratio for HE-33, HE-48 and HE-44 and model a baseline scenario of binarymixing between the injectate and background fluids where no mineralisation occurs(Figure 6A and Table 5). If no mineralisation has occurred, δ13CCO2 (‰) VPDBmeasured at the monitoring wells HE-31, HE-48 and HE-44 should be around theexpected levels shown in Table 5 and the CO2 / 3He ratio measured at the monitoringwells HE-31, HE-48 and HE-44 should be around the expected levels shown in Table 5.Furthermore, the CO2 δ13C (‰) VPDB and CO2 / 3He measured at the monitoringwells HE-31, HE-48 and HE-44 should plot on the mixing line between the Carbfix injectate and background CO2 on their respective mixing ratios (Figure 6A). Note that despite monitoring wells HE-31 and HE-48 producing 75% and 77% backgroundrespectively, CO2 / 3He and δ13CCO2 are still significantly shifted towards Carbfix injectatesignals. This is because DIC in the injectate is approximately six times more concentrated than background fluids (50.6 mM vs.8.36 mM). Monitoring wells do not plot on mixing line, instead recording lowerCO2 / 3He and higher δ13CCO2 than expected for this baseline scenario (Table 5). Thisdivergence is highest in the wells closest to the Carbfix injection well that receive thehighest percentage of injectate relative to background (HE-31 and HE-48). Table 5: Comparison between expected and measured CO2 / 3He and δ13CCO2values in Carbfix monitoring wells. Expected values correspond to CO2 / 3He and δ13CCO2data predicted for monitoring wells if no modification (i.e., no mineralisation) of CO2occurs in the Carbfix reservoir, meaning each well would produce a Carbfix injectate-background CO2mix equivalent to its respective background mixing ratio. CO2 / 3He δ13CCO2 (‰ VPDB)Background mixing ratio Expecte Measure Differenc Expecte Measure Differenc d d e d d e HE-31 75%7.0 x2.0 x 109 -5.0 x 109 -4.5 -3.4 +1.1109HE-48 77%6.8 x1.8 x 109 -5.0 x 109 -4.5 -3.5 +1.0109HE-44 90%5.0 x1.4 x 109 -3.6 x 109 -4.1 -3.6 +0.5109Modelling mineralisation Loss of CO2 relative to inert 3He in the Carbfix reservoir compared to expectedvalues for injectate-background mixing suggests there is a CO2removal mechanism active in the reservoir that is most prevalent between injection well HN-16 and closest monitoring well HE-31. Microbial activity is not expected to be an active mechanism of CO2removal given the reservoir temperature of 265°C. Importantly, CO2mineralisation above 193°C enriches remaining residual CO2in13C relative to12C, increasing δ13CCO2(Bottinga, 1969; Ohmoto and Rye, 1979; Clark and Fritz, 1997). Measured monitoring well δ13CCO2values are higher than expected for the baseline scenario of injectate- background mixing only (Figure 6A and Table 5), suggesting mineralisation is a plausible cause of CO2 loss in the reservoir. Chronology with mixing We can model the expected evolution of injectate isotope values if mineralisation is occurring at the reservoir temperature of 265°C (Figure 6B). Timing of mineralisation relative to background fluid mixing (i.e., before, during or after) is important, because this impacts the starting isotope values prior to mineralisation-induced fractionation, and the extent of any syn-or-post-mineralisation dilution from background values. There are two end-member scenarios for the chronology of mineralisation and mixing: (1) all mineralisation occurs before any mixing, or (2) all mixing occurs before any mineralisation. In reality, both likely proceed simultaneously along the flow paths between injection and monitoring wells. Observations and modelling from other Carbfix projects indicated that scenario (1) is a better depiction of reality than scenario (2)(Snæbjörnsdóttir et al., 2018a; Clark et al., 2020; Marieni et al., 2021; Galeczka et al.,2022). With this in mind, we model two mineralisation-mixing chronologies; one where all mineralisation occurs before any background mixing (blue line; Figure 6B) andanother where mineralisation and mixing progress simultaneously (green line; Figure6B). Mineralisation is modelled by assuming there is no3He loss during mineralisation, meaning changes in CO2 / 3He are indicative of CO2behaviour and background mixing. Evolution of δ13CCO2is predicted using an open system model of Rayleigh fractionation, on the premise that once CO2is removed by mineralisation, it is unable to contribute to subsequent reactions: ^^^^^^^^^^ = ^^ ^^^^^^^^^^ + ^^^^^^^^^^^^^^^^^^^ × ^^^^ ^^ (Equation 10)where subscripts (^^) and (^^^^) are the carbon isotope value of the remaining andCarbfix injectate CO2 respectively, ^^^^^^^^^^^ is the temperature dependent carbonisotope enrichment factor when CO2 mineralises as calcite (1.55 at 265°C; Ohmoto andRye 1979), and ^^ is the fraction of the Carbfix injectate CO2 that remains.Fractionated injectate CO2(blue line; Figure 6B) will be diluted towardsbackground CO2 after mineralisation (i.e., shift from the blue line on Figure 6B towardsHE-33). For simultaneous mineralisation and mixing, 10% is mineralised, followed by 10% mixing with background fluids. The resulting δ13CCO2value is calculated based on how much the remaining injectate CO2 comprises of the overall CO2 pool after 10% has been removed. This results in an evolution of δ13C values that are initially similar to the mineralisation only scenario, but begin to mix back towards background values (HE-33) as CO2 is mineralised and lost from the remaining mix (Figure 6B). Outputs Modelled simultaneous mineralisation and mixing in the Carbfix reservoirintersects the measured monitoring well values for HE-31 and HE-48 (Figure 6B). However, uncertainty ranges for monitoring wells HE-31, HE-48 and HE-44 overlap with background (HE-33), meaning these data are not conclusive about the fate of CO2 in the reservoir because monitoring wells could producing background CO2 only. To test this, CO2 tracers must be combined with a parameter that has a distinct background fromthe Carbfix injectate and is unaffected by reactions in the reservoir.Using δ18OH2O as a non-reactive tracer As has previously been discussed, CO2 constitutes <1% of the overall oxygen isotope pool in the gas charged condensate. This is most concentrated source ofdissolved CO2 across the whole Carbfix system, meaning CO2 comprises an evensmaller portion of the oxygen isotope pool in reservoir and production fluids. The key implication of this is δ18OH2Ovalues are unaffected by CO2and instead track fluid mixing.The Carbfix injectate δ18OH2O is 1.5‰ higher than background δ18OH2O in HE-33 (Table3 and 4). Monitoring wells should therefore record δ18OH2O values that correspond to aninjectate-background δ18O mix proportional to their respective background mixing ratios (Table 1). In this capacity, δ18OH2Odata are in effect serving the same purpose as added non-reactive tracers previously used at Hellisheiði (Kristjansson et al., 2016; Ratouis et al., 2022) and in CarbFix projects (Matter et al., 2014, 2016; Gunnarsson et al., 2018; Clark et al., 2020). By combining these data with δ13CCO2values, we can assess the fate of CO2using the fractionation of carbon isotopes (Figure 6), and then use δ18OH2Odata to determine if monitoring wells are producing injectate-background mixes or background only. As with CO2 / 3He data, if no mineralisation is occurring in the reservoir, Carbfix monitoring wells should plot on an injectate-background mixing line (Figure 7A). Once again this is not the case, with monitoring wells instead recording δ13CCO2values higher than predicted for the baseline scenario. Critically, δ18OH2Ovalues of monitoring wells HE-31 and HE-48 are distinct frombackground (HE-33) and trend back towards the Carbfix injectate value, indicating thepresence of injectate fluids in the monitoring wells. Modelled simultaneous mineralisation and mixing (green line; Figure 7B) produces a trend that intersects with measured monitoring well values. Projection of a monitoring well dataset regression line (R2= 0.72) indicates a δ13C-derived CO2 mineralisation yield of ~70% from these data. Significance and implications Shifts in CO2 / 3He, δ13CCO2 and δ18OH2O values across the Carbfix scrubbing towerand storage reservoir systems correspond to comparable percentages of CO2 dissolution (in scrubbing tower) and mineralisation (in storage reservoir) previously published(Gunnarsson et al., 2018; Clark et al., 2020). Enrichment of 13C in Carbfix scrubbing tower gas outlet (Figure 5) and reservoir well samples (Figure 6 and Figure 7) is particularly significant because this is directly and uniquely attributable to dissolution and mineralisation reactions. This is encouraging for the wider application of inherent isotope tracers to the monitoring and verification of in-situ CO2 mineralisation because there are specificcharacteristics of this Carbfix project that limit the effectiveness of inherent tracers inquantifying mineralisation. These characteristics are not shared by the majority ofcurrently proposed in-situ CO2 mineralisation projects, meaning verification using inherent tracers should be more effective at future projects. CO2 injected at Carbfix originates from the same geothermal reservoir it is beingreinjected back into. Although CO2 dissolution in the Carbfix scrubbing tower doesdeplete injected CO2in13C relative to the majority of produced CO2at Hellisheiði, it is still within 1-2‰ of background CO2δ13C. In addition, because the storage reservoirtemperature is ~265°C, the ^^^^^^^^^^^ and the associated shifts in δ13CCO2 resulting frommineralisation are relatively small compared to most carbonate forming environments inthe shallow subsurface. Each of these factors individually, but particularly when combined, increase the risk of mineralisation related signals interfering with background values. This lack of distinction is critical for the effectiveness of inherent isotope tracers,as we see in Figure 6, and as discussed in the review of Mayer et al., (2015) regardingthe use of CO2 isotope ratios as a leakage detection tool at CO2 storage sites. The majority of in-situ CO2 mineralisation projects currently proposed will injectCO2 supplied from direct air capture (DAC; i.e., the atmosphere) or industrial processes(i.e., combustion of fossil fuels) into storage reservoirs with temperatures of <100°C. This means injected CO2 will have a lower starting δ13C value, and mineralisation will shift δ13CCO2 by a larger extent than we observed in the higher temperature Carbfix reservoir.Atmospheric CO2 has a δ13C of -8.4‰ VPDB, whereas industrial sourced CO2 can haveδ13CCO2 >20‰ lower than this.DAC example Taking the Orca DAC project in Iceland as an example, it captures and injects4000t / year of atmospheric CO2 for storage via in-situ CO2 mineralisation in a basalticreservoir that is 35-65°C. The fractionation effect(s), or lack of, from DAC technology on CO2 and noble gas isotopes have yet to be established. Previous work investigating the fractionation effects of point source CO2 capture technologies such as amine capture indicated that13C depletions of up to ~20‰ were evident (Flude et al., 2016, 2017). ^^^^^^^^^^^at 100°C is -4.0‰ and decreases to -10.7‰ at 20°C (Ohmoto and Rye, 1979). If we assume the CO2 capture process does not significantly alter δ13CCO2, injected CO2 will have a δ13C value of atmospheric CO2 (-8.4‰ VPDB; Graven et al., 2020). ^^^^^^^^^^^for the Orca reservoir temperature range of 35-65°C is9.2-6.5‰ (Ohmoto and Rye, 1979). Inputting these figures into the open system Rayleighfractionation equation (Equation 10), we can predict the δ13C evolution of injected OrcaCO2 (see Table 6).The extent to which this shift in δ13CCO2is recorded in monitoring well(s) will depend on the relative concentrations of injected fractionated CO2and un-fractionatedbackground CO2, just as we have shown with the Carbfix data. Groundwater sourcedDIC in Iceland is reported to have a δ13CCO2value of -12.5‰ (Stefánsson et al., 2016), and mineral sourced DIC is generally cited as higher than this (Sveinbjörnsdóttir et al., 1995). This means that once mineralisation progresses beyond 50%, the remaining injected DAC CO2should be distinctly depleted in13C relative to background sources of CO2(Table 6), making detection more likely. Table 6: Predicted evolution of CO2 injected at the Orca DAC project in Icelandat the minimum and maximum storage reservoir temperature, assuming a starting δ13C of atmospheric CO2 (Graven et al., 2020) and open system Rayleigh fractionation. Note this evolution does not include the dilution effects of CO2 loss and mixing with background DIC present in the reservoir. Remaining CO2 Percentage CO2 δ13C (‰) VPDB mineralised 35°C 65°C0% -8.4 -8.410% -9.4 -9.120% -10.5 -9.930% -11.7 -10.740% -13.1 -11.750% -14.8 -12.960% -16.8 -14.470% -19.5 -16.280% -23.2 -18.990% -29.6 -23.499% -50.8 -38.3To summarise, the larger the (1) distinction between injected and background δ13C CO2, (2) ^^^^^^^^^^^and (3) concentration and / or proportion of injected CO2in monitoring well(s) relative to the greater the potential for accurate quantification of in-situ CO2 mineralisation. Using δ18OH2O as a non-reactive tracer As previously discussed, δ18OH2O data at Carbfix are not impacted by CO2because of the dominance of H2O in the oxygen isotope pool. This allows us to identifythe presence of Carbfix injectate fluids in the monitoring wells despite the loss of CO2and carbon baring tracers through mineralisation. Given that large volumes of water are required for in-situ CO2mineralisation, we propose that current and future mineralisation projects could also use δ18OH2Ovalues of injection fluids as a non-reactive tracer. These data could be compared to reactive tracers for determining mineralisation yields (Matter et al., 2014) and tracking fluid mixing. Injectate-background δ18OH2Odifference in this study was 1.5‰. Project operators could select injection waters that are particularly enriched or depleted in18O to provide the largest distinction feasible from background fluids. Assuming a source of these fluids exists, this would be a relatively inexpensive means of tracking CO2fate and fluid mixing because tracing would be provided from the inherent chemistry of the injectate. Conclusion In this study we assess the capability of inherent noble gas (in the form of 3He),CO2and H2O isotopes to monitor and verify in-situ CO2mineralisation at a Carbfix CCS project in Iceland. We first report measurements from across the host geothermal field, Hellisheiði,to identify the performance of tracers in identifying the source and mixing extent of fluids, and the prevalence of gas-water-rock reactions. Noble gas ratios identify two-part mixing between magmatic and atmospheric noble gases, while CO2 / 3He and δ13CCO2 indicate a magmatic source of CO2 as expected. H2O isotope ratios suggest source meteoric waters are modified by a combination of high temperature water-rock interaction and water-steam phase separation during geothermal production. Results of measurements from the Carbfix scrubbing tower show reductions inCO2 / 3He between gas inlet and outlet (geothermal gas and gas-charged condensate) samples that correspond to 50% (± 4%) CO2 dissolution. This is comparable to the previously reported 56% dissolution of Gunnarsson et al., (2018). From these data wecalculate that the CO2 / 3He ratio and δ13CCO2 of dissolved CO2 are 9.6 x 109 (± 8.9 x 108)and -5.0‰ (± 0.2‰) VPDB respectively.Comparison of these estimated values with measured Carbfixmonitoring well isotope data indicates that CO2 / 3He is lower and δ13CCO2 is higher than expected in monitoring wells for a baseline scenario where no mineralisation occurs. Given this, we model the evolution of injectate CO2 / 3He and δ13CCO2 for different chronologies of mineralisation and mixing at the reservoir temperature of 265°C. Monitoring well data intersect modelled mineralisation scenarios at similar extents of mineralisation previously recorded (Clark et al., 2020). δ18OH2O data are key for distinguishing between the remaining injectate and background CO2 in monitoring wells because the combined effects of fractionation and CO2loss make injectate and background CO2 / 3He and δ13C indistinguishable. We believe these results are promising for the wider application of inherent isotope tracers to the monitoring and verification of in-situ CO2mineralisation. Mostprojects plan to inject isotopically distinct CO2 into lower temperature storage reservoirs,which will increase the distinction between background and injected fractionated CO2.Using the inherent chemistry of injected CO2and H2O to verify storage avoids the additional costs of added tracers and can provide direct evidence of mineralisation that is uniquely attributable to these reactions. Our findings are therefore of particular interest to the growing number of carbon dioxide removal (CDR) technologies such as DAC that are targeting durable geological storage. It will be understood that the present embodiments are provided by way of example only, and that various modifications can be made to the present embodiments without departing from the scope of the invention.

Claims

CLAIMS1. A method of monitoring carbon dioxide (CO2) mineralisation and / or dissolution ina storage reservoir, the method comprising: injecting a feed of carbon dioxide into the storage reservoir, wherein the feed hasa first ratio of 13C / 12C, a first ratio of CO2 to a noble gas, and a first ratio of 18O / 16O;producing a fluid downstream of the storage reservoir, wherein the produced fluid has a second ratio of13C / 12C, a second ratio of CO2 / noble gas, and a second ratio of18O / 16O; measuring the second ratio of 13C / 12C of the produced fluid; andmeasuring the second ratio of CO2 to noble gas and / or measuring the secondratio of 18O / 16O of the produced fluid.

2. A method according to claim 1, comprising measuring the second ratio of 13C / 12Cof the produced fluid and measuring the second ratio of CO2 to noble gas of the producedfluid.

3. A method according to claim 2, wherein the method comprises quantifying theamount of carbon dioxide mineralisation and / or dissolution in the reservoir based on acomparison, e.g. a difference, between the first 13C / 12C ratio and the second 13C / 12C ratio,and on a comparison, e.g. a difference, between the first CO2 / noble gas ratio and the second CO2 / noble gas ratio.

4. A method according to claim 1, comprising measuring the second ratio of 13C / 12Cof the produced fluid and measuring the second ratio of 18O / 16O of the produced fluid.

5. A method according to claim 4, wherein the method comprises quantifying theamount of carbon dioxide mineralisation and / or dissolution in the reservoir based on acomparison, e.g. a difference, between the first 13C / 12C ratio and the second 13C / 12C ratio,and on a comparison, e.g. a difference, between the first18O / 16O ratio and the second18O / 16O ratio.

6. A method according to any preceding claim, comprising performing calibration ofthe storage reservoir.

7. A method according to claim 6, injecting a calibration feed into thestorage reservoir, e.g. via at least one injection well, and producing a calibration fluid downstream of the storage reservoir, e.g. via at least one producing well.

8. A method according to claim 6 or claim 7, comprising applying the calibrationdata, to one or more of: (i) a / the difference or shift in the13C / 12C ratio between the feed and the produced fluid; (ii) a / the difference or shift in the CO2 / noble gas ratio between the feed and the produced fluid; (iii) a / the difference or shift in the18O / 16O ratio between the feed and the produced fluid.

9. A method according to any preceding claim, comprising determining thepercentage of CO2captured, e.g. mineralised and / or dissolved, in the storage reservoir.

10. A method according to any preceding claim, wherein the storage reservoircomprises or is a subterranean formation.

11. A method according to claim 10, wherein the storage reservoir comprises or is abasaltic rock formation and / or a mafic or ultramafic rock formation.

12. A method according to any preceding claim, comprising injecting the feed via atleast one injection well, and producing the fluid via at least one production well or monitoring well, wherein the storage reservoir is located between the at least one injection well and the at least one production well or monitoring well.

13. A method according to any preceding claim, comprising dissolving carbon dioxideinto an aqueous solution, to prepare the injection fluid.

14. A method for monitoring mineralisation of carbon dioxide (CO2) injected into ageological reservoir, the method comprising:providing a system comprising: an injection well for injecting fluid into the geological reservoir, and an extraction well arranged a predetermined distance from the injection well, for extracting fluid samples from the geological reservoir,performing a tracer test, in order establish that a flow path exists between the injection well and the extraction well, and characterize the flow path by: determining / estimating a period of time it takes a fluid, injected through the injection well into the geological reservoir, to reach the extraction well, determining / estimating a mixing ratio of background reservoir fluid and injected fluid at the extraction well, obtaining background reservoir fluid data including an estimated 13C / 12C ratio ofCO2 in the background reservoir fluid at the extraction well and / or an estimated CO2 tonoble gas ratio in the background reservoir fluid at the extraction well,providing an injectate comprising water, CO2 and noble gas,performing first measurements on the injectate or on a plurality of fluids which has been merged to form the injectate, in order to estimate a13C / 12C ratio of CO2in theinjectate and / or to estimate a CO2 to noble gas ratio in the injectate,injecting the injectate into the geological reservoir through the injection well,extracting a mixed fluid sample from the extraction well after the period of timehas passed, the mixed fluid sample comprising a mixture of background reservoir fluid and injectate fluid, performing second measurements on the mixed fluid sample, in order to estimatea 13C / 12C ratio of CO2 of the mixed fluid at the extraction well and / or to estimate a CO2 tonoble gas ratio of the mixed fluid at the extraction well, calculating the expected13C / 12C ratio of CO2and / or the expected CO2to noblegas ratio of the mixed fluid at the extraction well if no mineralisation of CO2 has occurredbetween the injection well and the extraction well, based on the estimated mixing ratio at the extraction well, the background reservoir fluid data and the estimated13C / 12C ratioof CO2 in the injectate and / or the estimated CO2 to noble gas ratio in the injectate,comparing the expected13C / 12C ratio of CO2 and / or the expected CO2 to noblegas ratio of the mixed fluid at the extraction well with the estimated 13C / 12C ratio of CO2and / or estimated CO2 to noble gas ratio in the mixed fluid at the extraction well,respectively, in order to determine if mineralisation has occurred between the injection well and the extraction well and thereby monitor the mineralisation of carbon dioxide injected into the geological reservoir.

15. A monitoring system for monitoring mineralisation of carbon dioxide (CO2)injected into a geological reservoir, the system comprising:an injection well for injecting fluid the geological reservoir, an extraction well arranged a predetermined distance from the injection well, a fluid extraction system for extracting fluid samples from the geological reservoir, a measuring system for performing a tracer test to: establish that a flow path exists between the injection well and the extraction well, and characterize the flow path by: determining / estimating a period of time it takes a fluid, injected through the injection well into the geological reservoir, to reach the extraction well, anddetermining / estimating a mixing ratio of background reservoir fluid and injected fluid at the extraction well, the measuring system further being configured for performing first measurements on an injectate comprising water, CO2and noble gas, or on a plurality of fluids which has been merged to form the injectate, in order to estimate a13C / 12C ratio of CO2in the injectate and / or to estimate a CO2to noble gas ratio in the injectate, an injection device for injecting the injectate into the geological reservoir through the injection well, the fluid extraction system further being configured for extracting a mixed fluid sample from the extraction well after the period of time has passed, the mixed fluid sample comprising a mixture of background reservoir fluid and injectate fluid, where the background reservoir fluid data includes an estimated13C / 12C ratio of CO2in the background reservoir fluid at the extraction well and / or an estimated CO2to noble gas ratio in the background reservoir fluid at the extraction well, the measuring system further being configured for performing second measurements on the mixed fluid sample, in order to estimate a13C / 12C ratio of CO2 of the mixed fluid at the extraction well and / or to estimate a CO2 to noble gas ratio of the mixed fluid at the extraction well, a computer system operatively connected to the measuring system configured to: calculate the expected13C / 12C ratio of CO2 and / or the expected CO2 to noble gas ratio of the mixed fluid at the extraction well if no mineralisation of CO2 has occurred between the injection well and the extraction well, based on the estimated mixing ratio at the extraction well, the background reservoir fluid data and the estimated13C / 12C ratio of CO2 in the injectate and / or the estimated CO2 to noble gas ratio in the injectate,compare the expected ratio of CO2 and / or the expected CO2 to noble gas ratio of the mixed fluid at the extraction well with the estimated13C / 12C ratio of CO2and / or estimated CO2to noble gas ratio in the mixed fluid at the extraction well, respectively, in order to determine if mineralisation has occurred between the injection well and the extraction well and thereby monitor the mineralisation of carbon dioxide injected into the geological reservoir.

Images