Natural CO2 Reservoir Research Articles

Causes of underpressure in natural CO2reservoirs and implications for geological storage

Abstract Geological carbon storage has the potential to reduce anthropogenic carbon dioxide emissions, if large volumes can be injected and securely retained. Storage capacity is limited by regional pressure buildup in the subsurface. However, natural CO2 reservoirs in the United States are commonly underpressured, suggesting that natural processes reduce the pressure buildup over time and increase storage security. To identify these processes, we studied Bravo Dome natural CO2 reservoir (New Mexico, USA), where the gas pressure is up to 6.4 MPa below the hydrostatic pressure, i.e., less than 30% of the expected pressure. Here, we show that the dissolution of CO2 into the brine reduces the pressure by 1.02 ± 0.08 MPa, because Bravo Dome is isolated from the ambient hydrologic system. This challenges the assumption that the successful long-term storage of CO2 is limited to open geological formations. We also show that the formation containing the reservoir was already 2.85 ± 2.02 MPa underpressured before CO2 emplacement. This is likely due to the overlying evaporite layer, which prevents recharge. Similar underpressured formations below regional evaporites are widespread in the midcontinent of the United States. This suggests the existence of significant storage capacities with properties similar to Bravo Dome, which has contained large volumes of CO2 over millennial time scales.

The role of soil flux and soil gas monitoring in the characterisation of a CO2 surface leak: A case study in Qinghai, China

Following the drilling of a shallow natural CO2 reservoir at the Qinghai research site, west of Haidong, China, it was discovered that CO2 was continuously leaking from the wellbore due to well-failure. The site has become a useful research facility in China for studying CO2 leakage and monitoring technologies for application to geological storage sites of CO2. During an eight day period in 2014, soil gas and soil flux surveys were conducted to characterise the distribution, magnitude and likely source of the leaking CO2.Two different sampling patterns were utilised during soil flux surveys. A regular sampling grid was used to spatially map out the two high-flux zones which were located 20–50m away from the wellhead. An irregular sampling grid, with higher sampling density in the high-flux zones, allowed for more accurate mapping of the leak distribution and estimation of total field emission rate using cubic interpolation. The total CO2 emission rate for the site was estimated at 649-1015kgCO2/d and there appeared to be some degree of spatial correlation between observed CO2 fluxes and elevated surface H2O fluxes.Sixteen soil gas wells were installed across the field to test the real-time application of Romanak et al.’s (2012) process-based approach for soil gas measurements (using ratios of major soil gas components to identify the CO2 source) using a portable multi-gas analyser. Results clearly identified CO2 as being derived from one exogenous source, and are consistent with gas samples collected for laboratory analysis. Carbon-13 isotopes in the centre of each leak zone (−0.21‰ and −0.22‰) indicate the underlying CO2 is likely sourced from the thermal decomposition of marine carbonates.Surface soil mineralisation (predominantly calcite) can be used to infer prior distribution of the CO2 hotspots and as a consequence highlighted plume migration of 20m in 11 years. The broadening of the affected area beyond the wellbore at the Qinghai research site markedly increases the area that needs surveying at sufficient density to detect a leak. This challenges the role of soil gas and soil flux in a CCS monitoring and verification program for leak detection, suggesting that these techniques may be better applied for characterising the source and emission rate of a CO2 leak, respectively.

Frictional behaviour and transport properties of simulated fault gouges derived from a natural CO2 reservoir

We investigated the effects of long-term CO2-brine-rock interactions on the frictional and transport properties of reservoir-derived fault gouges, prepared from both unexposed and CO2-exposed sandstone, and from aragonite-cemented fault rock of an active CO2-leaking conduit, obtained from a natural CO2 field (Green River, Utah). Direct shear experiments (5–90MPa effective normal stress; lab dry or wet; 20–100°C) showed that the sandstone-derived gouges are characterised by virtually normal stress- and temperature-independent friction coefficients (μ≈0.5–0.6). The data exhibited stable, velocity-strengthening behaviour moving towards near-neutral velocity-dependent behaviour with increasing effective normal stress. The carbonate-rich fault rock gouges exhibited higher friction coefficients (μ≈0.6–0.7), with a transition from velocity-strengthening behaviour at room temperature (dry) to velocity-weakening behaviour at 100°C (dry and wet), i.e. a transition from stable sliding to potentially unstable or seismogenic slip. Cross-fault permeability decreased up to 1.5 orders with increasing displacement, showing slightly lower values for the carbonate-rich gouges. We infer that the mechanical behaviour of fault gouges derived from the sandstones studied will not be strongly influenced by long-term CO2-exposure, due to the low content of reactive minerals in the protolith. Significant changes in frictional strength or (micro)seismic potential of faults present in a CO2 storage system are only expected when there is major carbonate precipitation in the fault damage zone due to rapid CO2 leakage and degassing.

Observational evidence confirms modelling of the long-term integrity of CO2-reservoir caprocks.

Storage of anthropogenic CO2 in geological formations relies on a caprock as the primary seal preventing buoyant super-critical CO2 escaping. Although natural CO2 reservoirs demonstrate that CO2 may be stored safely for millions of years, uncertainty remains in predicting how caprocks will react with CO2-bearing brines. This uncertainty poses a significant challenge to the risk assessment of geological carbon storage. Here we describe mineral reaction fronts in a CO2 reservoir-caprock system exposed to CO2 over a timescale comparable with that needed for geological carbon storage. The propagation of the reaction front is retarded by redox-sensitive mineral dissolution reactions and carbonate precipitation, which reduces its penetration into the caprock to ∼7 cm in ∼105 years. This distance is an order-of-magnitude smaller than previous predictions. The results attest to the significance of transport-limited reactions to the long-term integrity of sealing behaviour in caprocks exposed to CO2.

Noble gas fractionation during subsurface gas migration

Environmental monitoring of shale gas production and geological carbon dioxide (CO2) storage requires identification of subsurface gas sources. Noble gases provide a powerful tool to distinguish different sources if the modifications of the gas composition during transport can be accounted for. Despite the recognition of compositional changes due to gas migration in the subsurface, the interpretation of geochemical data relies largely on zero-dimensional mixing and fractionation models. Here we present two-phase flow column experiments that demonstrate these changes. Water containing a dissolved noble gas is displaced by gas comprised of CO2 and argon. We observe a characteristic pattern of initial co-enrichment of noble gases from both phases in banks at the gas front, followed by a depletion of the dissolved noble gas. The enrichment of the co-injected noble gas is due to the dissolution of the more soluble major gas component, while the enrichment of the dissolved noble gas is due to stripping from the groundwater. These processes amount to chromatographic separations that occur during two-phase flow and can be predicted by the theory of gas injection. This theory provides a mechanistic basis for noble gas fractionation during gas migration and improves our ability to identify subsurface gas sources after post-genetic modification. Finally, we show that compositional changes due to two-phase flow can qualitatively explain the spatial compositional trends observed within the Bravo Dome natural CO2 reservoir and some regional compositional trends observed in drinking water wells overlying the Marcellus and Barnett shale regions. In both cases, only the migration of a gas with constant source composition is required, rather than multi-stage mixing and fractionation models previously proposed.

The relevance of dawsonite precipitation in CO 2 sequestration in the Mihályi-Répcelak area, NW Hungary

Abstract A natural CO 2 reservoir system with a sandstone lithology in NW Hungary has been studied due to its similarities to a large saline reservoir formation that is widespread in the the Pannonian Basin (Central Europe) and is suggested to be one of the best candidates for industrial CO 2 storage. A range of analytical techniques has been used on core samples from CO 2 -containing sandstone layers that represent a wide range of pressures (90–155 bar), temperatures (79–95°C) and pore fluid compositions (total dissolved solids between 18 000 and 50 700 mg l −1 ) to identify the mineralogy and textural characteristics of the natural reservoir. The only clear CO 2 -related feature in the studied lithology was the occurrence of dawsonite (NaAlCO 3 (OH) 2 ) in a close textural relationship with albite. This is in clear agreement with our geochemical modelling results, which also underline the presence of albite as a precondition for the crystallization of dawsonite at the given P – T – X conditions. Our results suggest that, at least in the Pannonian Basin, dawsonite may be an important mineral for the safe sequestration of industrial CO 2 in the subsurface.

Determining CO2 storage potential during miscible CO2 enhanced oil recovery: Noble gas and stable isotope tracers

Rising atmospheric carbon dioxide (CO2) concentrations are fueling anthropogenic climate change. Geologic sequestration of anthropogenic CO2 in depleted oil reservoirs is one option for reducing CO2 emissions to the atmosphere while enhancing oil recovery. In order to evaluate the feasibility of using enhanced oil recovery (EOR) sites in the United States for permanent CO2 storage, an active multi-stage miscible CO2 flooding project in the Permian Basin (North Ward Estes Field, near Wickett, Texas) was investigated. In addition, two major natural CO2 reservoirs in the southeastern Paradox Basin (McElmo Dome and Doe Canyon) were also investigated as they provide CO2 for EOR operations in the Permian Basin. Produced gas and water were collected from three different CO2 flooding phases (with different start dates) within the North Ward Estes Field to evaluate possible CO2 storage mechanisms and amounts of total CO2 retention. McElmo Dome and Doe Canyon were sampled for produced gas to determine the noble gas and stable isotope signature of the original injected EOR gas and to confirm the source of this naturally-occurring CO2. As expected, the natural CO2 produced from McElmo Dome and Doe Canyon is a mix of mantle and crustal sources. When comparing CO2 injection and production rates for the CO2 floods in the North Ward Estes Field, it appears that CO2 retention in the reservoir decreased over the course of the three injections, retaining 39%, 49% and 61% of the injected CO2 for the 2008, 2010, and 2013 projects, respectively, characteristic of maturing CO2 miscible flood projects. Noble gas isotopic composition of the injected and produced gas for the flood projects suggest no active fractionation, while δ13CCO2 values suggest no active CO2 dissolution into formation water, or mineralization. CO2 volumes capable of dissolving in residual formation fluids were also estimated along with the potential to store pure-phase supercritical CO2. Using a combination of dissolution trapping and residual trapping, both volumes of CO2 currently retained in the 2008 and 2013 projects could be justified, suggesting no major leakage is occurring. These subsurface reservoirs, jointly considered, have the capacity to store up to 9 years of CO2 emissions from an average US powerplant.

Controls on CO2 storage security in natural reservoirs and implications for CO2 storage site selection

For carbon capture and storage to successfully contribute to climate mitigation efforts, the captured and stored CO2 must be securely isolated from the atmosphere and oceans for a minimum of 10,000 years. As it is not possible to undertake experiments over such timescales, here we investigate natural occurrences of CO2, trapped for 104–106yr to understand the geologic controls on long term storage performance. We present the most comprehensive natural CO2 reservoir dataset compiled to date, containing 76 naturally occurring natural CO2 stores, located in a range of geological environments around the world. We use this dataset to perform a critical analysis of the controls on long-term CO2 retention in the subsurface. We find no evidence of measureable CO2 migration at 66 sites and hence use these sites as examples of secure CO2 retention over geological timescales. We find unequivocal evidence of CO2 migration to the Earth’s surface at only 6 sites, with inconclusive evidence of migration at 4 reservoirs. Our analysis shows that successful CO2 retention is controlled by: thick and multiple caprocks, reservoir depths of >1200m, and high density CO2. Where CO2 has migrated to surface, the pathways by which it has done so are focused along faults, illustrating that CO2 migration via faults is the biggest risk to secure storage. However, we also find that many naturally occurring CO2 reservoirs are fault bound illustrating that faults can also securely retain CO2 over geological timescales. Hence, we conclude that the sealing ability of fault or damage zones to CO2 must be fully characterised during the appraisal process to fully assess the risk of CO2 migration they pose. We propose new engineered storage site selection criteria informed directly from on our observations from naturally occurring CO2 reservoirs. These criteria are similar to, but more prescriptive than, existing best-practise guidance for selecting sites for engineered CO2 storage and we believe that if adopted will increase CO2 storage security in engineered CO2 stores.

Isotopic analysis of sulfur cycling and gypsum vein formation in a natural CO2 reservoir

In order to assess the long-term security of geologic carbon storage, it is crucial to study the geochemical behavior of sulfur in reservoirs that store CO2. Fossil fuel combustion may produce mixtures of carbon dioxide and sulfur gases, and the geochemical effects of sulfur–CO2 cosequestration are poorly understood. This study examines sulfur mineralization from a core drilled in a stacked sequence of natural CO2 reservoirs near the town of Green River, Utah. These reservoirs include the Entrada and Navajo Sandstone, which are separated by the Carmel Formation caprock and transected by a system of CO2-degassing normal faults, through which saline CO2-charged brines discharge. Our objective in this study is to evaluate the mechanisms and timing of secondary mineral formation, particularly gypsum formation, in the CO2 reservoirs and intervening caprock. The Carmel Formation contains beds of gypsum within a fault zone. Secondary veins of gypsum exist throughout the Entrada Sandstone and Carmel Formation. We report sulfur and oxygen isotope data (δ34SSO4 and δ18OSO4, respectively) measured in gypsum and δ34S measured in pyrite, and the oxygen and hydrogen isotope composition (δ18O and δD, respectively) of gypsum hydration water. The multiple isotope approach allows us to trace the sources of sulfur in the reservoirs and, when combined with structural and petrological evidence, the progress of fluid-rock reactions and relative timing of vein mineralization.The secondary gypsum veins in the Carmel Formation derive from mixing of fluids with two isotopically distinct sulfate sources: sulfate from the gypsum beds within the Carmel Formation and sulfate-rich brines that originate from evaporites in the underlying Carboniferous Paradox Formation. The gypsum veins in the Entrada Sandstone have a relatively wide range of δ18OSO4, both isotopically more enriched in 18O and more depleted in 18O than the primary gypsum sources. We suggest that some aqueous sulfate in the Entrada Sandstone may cycle through multiple valence states as it undergoes reduction and reoxidation, resulting in the replacement of its oxygen atoms and allowing the occasional formation of gypsum with anomalous low δ18OSO4. Our data from gypsum hydration water indicates that groups of gypsum veins formed at two different times. Gypsum veins in the Entrada Sandstone and some veins in the Carmel Formation likely formed during Quaternary CO2-charged brine discharge events, while other veins located close to the gypsum beds in the Carmel Formation formed earlier, likely during cycles of dehydration and rehydration associated with the Laramide-age (40Mya) faulting. We conclude that calcium-sulfate mineral formation in brine-filled fractures may play an important role in inhibiting fluid migration in geologic reservoirs that contain CO2.

Noble gases preserve history of retentive continental crust in the Bravo Dome natural CO2 field, New Mexico

Budgets of 4He and 40Ar provide constraints on the chemical evolution of the solid Earth and atmosphere. Although continental crust accounts for the majority of 4He and 40Ar degassed from the Earth, degassing mechanisms are subject to scholarly debate. Here we provide a constraint on crustal degassing by comparing the noble gases accumulated in the Bravo Dome natural CO2 reservoir, New Mexico USA, with the radiogenic production in the underlying crust. A detailed geological model of the reservoir is used to provide absolute abundances and geostatistical uncertainty of 4He, 40Ar, 21Ne, 20Ne, 36Ar, and 84Kr. The present-day production rate of crustal radiogenic 4He and 40Ar, henceforth referred to as 4He⁎ and 40Ar⁎, is estimated using the basement composition, surface and mantle heat flow, and seismic estimates of crustal density. After subtracting mantle and atmospheric contributions, the reservoir contains less than 0.02% of the radiogenic production in the underlying crust. This shows unequivocally that radiogenic noble gases are effectively retained in cratonic continental crust over millennial timescales. This also requires that approximately 1.5 Gt of mantle derived CO2 migrated through the crust without mobilizing the crustally accumulated gases. This observation suggests transport along a localized fracture network. Therefore, the retention of noble gases in stable crystalline continental crust allows shallow accumulations of radiogenic gases to record tectonic history. At Bravo Dome, the crustal 4He⁎/40Ar⁎ ratio is one fifth of the expected crustal production ratio, recording the preferential release of 4He during the Ancestral Rocky Mountain orogeny, 300 Ma.

CO2 solubility in aqueous solutions containing Na+, Ca2+, Cl−, SO42− and HCO3-: The effects of electrostricted water and ion hydration thermodynamics

Dissolution of CO2 into deep subsurface brines for carbon sequestration is regarded as one of the few viable means of reducing the amount of CO2 entering the atmosphere. Ions in solution partially control the amount of CO2 that dissolves, but the mechanisms of the ion's influence are not clearly understood and thus CO2 solubility is difficult to predict. In this study, CO2 solubility was experimentally determined in water, NaCl, CaCl2, Na2SO4, and NaHCO3 solutions and a mixed brine similar to the Bravo Dome natural CO2 reservoir; ionic strengths ranged up to 3.4 molal, temperatures to 140 °C, and CO2 pressures to 35.5 MPa. Increasing ionic strength decreased CO2 solubility for all solutions when the salt type remained unchanged, but ionic strength was a poor predictor of CO2 solubility in solutions with different salts. A new equation was developed to use ion hydration number to calculate the concentration of electrostricted water molecules in solution. Dissolved CO2 was strongly correlated (R2 = 0.96) to electrostricted water concentration. Strong correlations were also identified between CO2 solubility and hydration enthalpy and hydration entropy. These linear correlation equations predicted CO2 solubility within 1% of the Bravo Dome brine and within 10% of two mixed brines from literature (a 10 wt % NaCl + KCl + CaCl2 brine and a natural Na+, Ca2+, Cl− type brine with minor amounts of Mg2+, K+, Sr2+ and Br−).

First Field Example of Remediation of Unwanted Migration from a Natural CO2 Reservoir: The Bečej Field, Serbia

The Bečej field, discovered in 1951 by the Petroleum Industry of Serbia (NIS), is one of the largest natural CO2 fields in Europe. Uncontrolled migration of CO2 out of the main reservoir, leading to subsurface seepage and surface leakage, was caused by the Bč-5 well blowout in 1968. Remediation measures were deployed in 2007 to reduce and prevent further leakage of CO2 from the Bečej natural CO2 field. To the best of our knowledge, this is the first field application of remediation measures deployed to remedy leakage from a natural CO2 reservoir – a natural analogue for an engineered geological storage site. Experiences and lessons learned from the Bečej field case are studied within the MiReCOL project (Mitigation and Remediation of CO2 Leakage). The project aims at developing a handbook of corrective measures, which can be considered in the event of significant irregularities and leakage from a CO2 storage site. We performed a comprehensive geological characterization of the Bečej field and interpreted the most recently collected monitoring data to assess the effectiveness of the remediation measures taken in 2007. A static model was constructed that comprises the main CO2 reservoir (Upper Cretaceous and Badennian) and several aquifers in the overburden (Pontian and Pliocene). Eight small hydrocarbon reservoirs are defined above the main CO2 pool at depths ranging from 450 to 900 m, suggesting that the Bečej CO2 field is a natural leaking system. The monitoring data indicate that the remediation measures were effective and have practically stopped the decline of reservoir pressure.

An integrated study of fluid–rock interaction in a CO2-based enhanced geothermal system: A case study of Songliao Basin, China

The reactive behavior of a mixture of supercritical CO2 and brine under physical–chemical conditions relevant to the CO2-based Enhanced Geothermal System (CO2-EGS) is largely unknown. Thus, laboratory experiments and numerical simulations were employed in this study to investigate the fluid–rock interaction occurring in the CO2-EGS. Rock samples and thermal–physical conditions specific to the Yingcheng Formation of Songliao Basin, China, an EGS research site, were used. Experiments were conducted by using of reactors at high temperature and pressure. Six batch reaction experiments injected with supercritical CO2 were designed at temperatures of 150–170°C and a pressure of 35MPa. Moreover, a separate experiment at the same experimental conditions without injection of CO2 was also conducted for comparison. Analyses of scanning electron microscopy (SEM) and X-ray diffraction (XRD) of the resulting solids were conducted to characterize changes in mineral phases. Numerical simulations were also performed under the same conditions as those used in the experiments. Significant mineral alterations were detected at the CO2-EGS reservoir, which may change the properties of fluid flow. The presence of supercritical CO2 led to an dissolution of primary minerals such as calcite and K-feldspar and precipitations of secondary carbonate such as calcite and ankerite. The numerical simulations were generally consistent with laboratory experiments, which provide a tool for scaling the time up for long period of reservoir simulations. The information currently available for the mineral alteration at high-temperature natural CO2 reservoirs is generally consistent with those of our lab experiments and numerical simulations.

Field-based stable isotope analysis of carbon dioxide by mid-infrared laser spectroscopy for carbon capture and storage monitoring.

A newly developed isotope ratio laser spectrometer for CO2 analyses has been tested during a tracer experiment at the Ketzin pilot site (northern Germany) for CO2 storage. For the experiment, 500 tons of CO2 from a natural CO2 reservoir was injected in supercritical state into the reservoir. The carbon stable isotope value (δ(13)C) of injected CO2 was significantly different from background values. In order to observe the breakthrough of the isotope tracer continuously, the new instruments were connected to a stainless steel riser tube that was installed in an observation well. The laser instrument is based on tunable laser direct absorption in the mid-infrared. The instrument recorded a continuous 10 day carbon stable isotope data set with 30 min resolution directly on-site in a field-based laboratory container during a tracer experiment. To test the instruments performance and accuracy the monitoring campaign was accompanied by daily CO2 sampling for laboratory analyses with isotope ratio mass spectrometry (IRMS). The carbon stable isotope ratios measured by conventional IRMS technique and by the new mid-infrared laser spectrometer agree remarkably well within analytical precision. This proves the capability of the new mid-infrared direct absorption technique to measure high precision and accurate real-time stable isotope data directly in the field. The laser spectroscopy data revealed for the first time a prior to this experiment unknown, intensive dynamic with fast changing δ(13)C values. The arrival pattern of the tracer suggest that the observed fluctuations were probably caused by migration along separate and distinct preferential flow paths between injection well and observation well. The short-term variances as observed in this study might have been missed during previous works that applied laboratory-based IRMS analysis. The new technique could contribute to a better tracing of the migration of the underground CO2 plume and help to ensure the long-term integrity of the reservoir.

Insights into interconnections between the shallow and deep systems from a natural CO2 reservoir near Springerville, Arizona

If carbon dioxide (CO2) sequestration into deep geologic reservoirs is to be accepted by the public and environmental regulators, the possibility of upward leakage into shallow groundwater should be acknowledged and those processes well-understood. Studies of natural CO2 reservoirs and their connection (or lack thereof) with the shallow subsurface is one way to explore these issues. A natural reservoir near Springerville, Arizona has leaked CO2 to the surface along a fault zone for thousands of years, creating large travertine deposits. In recent times, the CO2 leak rates have declined significantly yet the shallow aquifer is still highly enriched in CO2. In this study, using water level data and simulations we demonstrate that the fault zone likely provides hydrologic communication between the shallow aquifer and the deeper reservoir. It is reasonable to assume, therefore, that the source of the CO2 in wells completed within the fault zone is the deeper CO2 reservoir. We present water chemistry data to demonstrate the geochemical impact of this CO2 on shallow groundwater quality. Interestingly, arsenic concentrations are elevated, but other trace metals concentrations are not. Arsenic and chloride concentrations co-vary, suggesting perhaps an external source of both elements rather than an in situ release of As due to CO2 attack on shallow aquifer sediments. Observations at this site demonstrate that hydraulic communications between shallow and deep layers and upward CO2 migration does not preclude long-term viability of a substantial CO2 reservoir at depth. We present multi-phase flow simulations to illustrate possible mechanisms trapping the CO2 at depth. Collectively, these analyses show that some degree of upward CO2 leakage may not be necessarily incompatible with the overarching goals of sequestering CO2 and protecting shallow groundwater.

Using natural CO2 reservoir to constrain geochemical models for CO2 geological sequestration

Numerical modeling of geochemical transport processes is necessary to investigate long-term CO2 storage in deep saline formations, because aluminosilicate mineral alteration is very slow under ambient deep-formation conditions and is not amenable to experimental study. Geochemical transport modeling can solve many problems and answer questions related to CO2 geological sequestration. The numerical modeling provides valuable insights regarding the physical and chemical consequences of CO2 injection in the subsurface environment. However, the reliability and applicability of the models need to be tested and validated if they are applied for CO2 geological sequestration. Issues on model validations are important if CO2 injection technologies are to be implemented safely, efficiently, and predictably. Validation of geochemical transport models could be different from conventional model validation methods for groundwater flow and solute transport. For the short-term behaviors, the models can be validated using laboratory and field experiments. For the long-term mineral alteration and CO2 sequestration, the natural analogue using high-pressure CO2 reservoirs could be a best way to validate the model. In this paper, a natural CO2 reservoir in southern Songliao Basin of China, which is past accumulations of CO2 in geological formation associated with magmatic or volcanic activity, was selected. Although the length of CO2 exposure and hence the rates of reaction for the natural system is not known in detail, we have shown that it is indeed possible to use observation data of mineral alteration in the natural CO2 reservoir to constrain thermodynamic and kinetic data of minerals used in the model, and to confine conditions of temperature, pressure, salinity, and primary mineral composition.

Further Insights Into Interconnections between the Shallow and Deep Systems from a Natural CO2 Reservoir Near Springerville, Arizona, U.S.A.

If carbon dioxide (CO 2 ) sequestration into deep geologic reservoirs is to be accepted by the public and environmental regulators, the possibility of upward leakage into shallow groundwater should be acknowledged and those processes well-understood. Studies of natural CO 2 reservoirs and their connection (or lack thereof) with the shallow subsurface is one way to explore these issues. A natural reservoir near Springerville, Arizona, U.S.A. has leaked CO 2 to the surface along a fault zone for thousands of years, creating large travertine deposits. In recent times, the CO 2 leak rates have declined significantly yet the shallow aquifer is still highly enriched in dissolved CO 2 . In previous studies, using water level data and simulations we demonstrate that the fault zone provides hydrologic communication between the shallow aquifer and the deeper reservoir. It is reasonable to assume, therefore, that the source of the CO 2 in wells completed within the fault zone is the deeper CO 2 reservoir. We present water chemistry data to demonstrate the geochemical impact of this CO 2 on shallow groundwater quality. Interestingly, arsenic concentrations are elevated, but other trace metals concentrations are not. Previous studies [1] , [2] , [3] showed that CO 2 originating from magmatic and deep crustal origin is migrating upward along the fault and dissolving into the shallow groundwater. Saline waters are also mixing, to a much lesser degree, but their source was unknown. Here we present strontium isotope data that clearly shows the source to be water/rock interactions with reservoir rocks, which include Paleozoic carbonates, evaporites and shale units.

The Green River Natural Analogue as A Field Laboratory To Study the Long-term Fate of CO2 in the subsurface

Understanding the long-term response of CO2 injected into porous reservoirs is one of the most important aspects to demonstrate safe and permanent storage. In order to provide quantitative constraints on the long-term impacts of CO2-charged fluids on the integrity of reservoir-caprock systems we recovered some 300m of core from a scientific drill hole through a natural CO2 reservoir, near Green River, Utah. We obtained geomechanical, mineralogical, geochemical, petrophysical and mineralogical laborator y data along the entire length of the core and from non CO2-charged control samples. Furthermore, we performed more detailed studies through portions of low permeability layers in direct contact with CO2-charged layers. This was done to constrain the nature and penetration depths of CO2-promoted fluid-mineral reaction fronts. The major reactions identified include the dissolution of diagenetic dolomite cements and hematite grain coatings, and the precipitation of ankerite and pyrite and have been used as input for geochemical 1D reactive transport modelling, to constrain the magnitude and velocity of the mineral-fluid reaction front. In addition, we compared geomechanical data from the CO2-exposed core and related unreacted control samples to assess the mechanical stability of reservoir and seal rocks in a CO2 storage complex following mineral dissolution and precipitation for thousands of years. The obtained mechanical parameters were coupled to mineralogy and porosity. Key aim of this work was to

Fault seal analysis of a natural CO2 reservoir in the Southern North Sea

A geomechanical and fault seal analysis of the fault-bound natural CO2 reservoir of the Fizzy Field, Southern North Sea, shows that reactivation of, and leakage along the bounding fault is unlikely. Reservoirs are juxtaposed along the fault but shale-gouge ratio calculations indicate that the fault rock prohibits across-fault leakage of CO2. This study illustrates that, even though the fault is orientated favourably for reactivation relative to present day stress and uncertainties about the geometries remain, fault seal is not the limiting factor in retention of CO2 at the Fizzy field.

U.S. Geological Survey Carbon Sequestration – Geologic Research and Assessments

Abstract In 2007, the U.S. Energy Independence and Security Act authorized the U.S. Geological Survey (USGS) to conduct a national assessment of geologic storage resources for anthropogenic carbon dioxide (CO2) and to evaluate the national technically recoverable hydrocarbon resources resulting from CO2 injection and storage through CO2-enhanced oil recovery (CO2-EOR). In addition, the USGS is addressing several other areas of carbon sequestration research that include study of natural CO2 and helium reservoirs as analogues for anthropogenic CO2 storage, the economics of CO2 storage and CO2-enhanced oil recovery, and induced seismicity associated with CO2 geologic storage.