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Abstract Carbon sequestration is an important measure to reduce greenhouse gas emissions. This paper introduces a new method of carbon sequestration using CO 2 waterless fracturing technology. Based on the supporting technology system with independent intellectual property rights, waterless fracturing field tests were carried out on 19 wells in Jilin oilfield. The on-site monitoring data shows that CO 2 stays in a supercritical state for a long time in the process of waterless fracturing, soaking and flowback, which is favourable for carbon sequestration. The geological model of H87 test area was established to simulate and evaluate CO 2 recovery after fracturing. The results show that the storage ratio of CO 2 waterless fracturing is 76.46%. Meanwhile, the production after waterless fracturing is 2.4 times that after water-based fracturing with the same scale, and the average single well operation saves 1512 m3 water. It can be seen that CO 2 waterless fracturing is a new type of carbon sequestration technology with high storage efficiency, good stimulation effect, significantly reduction of water consumption during oil and gas reservoir development and has broad market prospects. [ABSTRACT FROM AUTHOR]

Thermodynamic models are often used to quantify fluid-rock interactions. The validity of such models critically depends on the accuracy of the thermodynamic database used. This study evaluated the quality of existing PHREEQC databases ( phreeqc.dat, llnl.dat , and core10.dat ) through the analysis of mineral saturation states for various carbonates, sulfur-containing minerals, silicates, and hydroxides. The comparison between data from available equilibrated dissolution-precipitation experiments and predicted saturation states reveals: i) systematic deviations when using phreeqc.dat at temperatures higher than ~ 90 °C; ii) a lack of direct solubility measurements of numerous sulfide and silicate minerals; iii) systematic solubility underestimates for kaolinite and brucite. To address these issues the carbfix.dat database was created based on the core10.dat database, revising several mineral solubilities and aqueous species stabilities to improve our ability to model fluid-rock interactions during basalt-hosted mineral carbonation efforts. [ABSTRACT FROM AUTHOR]

Porous basaltic aquifers are currently being considered as a key geologic carbon storage host due to its widespread distribution and high reactivity. The co-injection of CO 2 and groundwater into basaltic reservoirs has the potential to mineralize this gas into solid phases within years, thanks to the release of divalent cations. Many natural basalts, however, contain substantial alteration minerals. Here we explore the potential of basalt alteration minerals to provide the Ca to fix injected CO 2 within calcite and/or aragonite. Preliminary results suggest that altered basaltic rocks can provide this Ca as efficiently as fresh basalts at 25 and 100 °C. Further experimental work is ongoing to confirm these findings at different temperatures and as a function of injected fluid chemistry. [ABSTRACT FROM AUTHOR]

We have performed quantum chemical computational studies to determine carbon dioxide affinity to carbon compounds and minerals, which could be present in shales. These studies shed light on the microscopic mechanisms of the possible carbon oxide sequestration processes. Our studies reveal that the carbon oxide can be adsorbed to various forms of carbon structures and also minerals such as periclase or illite. We find out that the strongest affinity of carbon oxide towards carbon structures occurs when the carbon structures exhibit sp 3 bonds. [ABSTRACT FROM AUTHOR]

Fractured shale formations are new potential target reservoirs for CO 2 capture and storage (CCS) and provide several potential advantages over storage in saline aquifers in terms of storage capacity, leakage risk, and cost savings from brownfield development. We used a geospatial-optimization, engineering-economic model to investigate the sensitivity of integrated CCS networks in Ohio, Pennsylvania, and West Virginia to reductions in CO 2 capture costs. These reductions in CO 2 capture costs were based on hypothetical cases where technological innovation reduced CO 2 capture costs. There were small differences in the spatial organization of the CCS deployment when the capture costs were reduced. We also found that the percent reduction in average cost of CCS systems became smaller as the CO 2 capture costs were decreased. [ABSTRACT FROM AUTHOR]

Residually trapped CO 2 is often assumed to be stable when simulating its long-term fate in geological storage reservoirs. Ostwald ripening is a mechanism that could potentially cause remobilization. We compare the case of bubbles of gas in a free liquid to that of a solid porous matrix. Using a new continuous pore network model, we gain insights on Ostwald Ripening in rocks and estimate time scales of evolution of multi-ganglia systems. Evolution is found to be highly dependent on system initialization as well as on pore structure. For residually trapped CO 2 in homogeneous rocks, a stable equilibrium is conceptually possible. [ABSTRACT FROM AUTHOR]

Low permeability caprock prevents migration of injected CO 2 towards the surface and potable water reservoirs. As a result of geochemical reactions among caprock minerals and CO 2 -saturated pore water, physical properties such as porosity, permeability and tortuosity may change, which could affect the sealing capability of caprocks. Due to the common high clay mineral content of caprocks, the reactivity of these minerals should be well-studied at CO 2 -saturated reservoir conditions. The main aim of this study is to understand better the geochemical behavior of CO 2 –brine–clay mineral system by using laboratory experiments at reservoir conditions on reference clays. [ABSTRACT FROM AUTHOR]

Carbon mineralisation has the potential to sequester and safely store large amounts of carbon dioxide (CO 2 ). However, this technology has not seen the same level of development as geological storage in sedimentary reservoirs. This is primarily because early work on carbonation of minerals focused on high temperature and pressure process routes, which are cost-prohibitive to accelerate the reaction from geological to industrial time scales. Bacteria-mediated carbon mineralisation of mine tailings [1] overcomes this impediment because it occurs at ambient temperature and standard pressure and the rock is already crushed. With abundant mafic and ultramafic rock, a highly developed mining sector, and a warm climate that promotes fast carbonation reactions, Australia presents an optimal region to develop this technology. We assess the mineralisation potential of Australia's existing and future nickel mine tailings and estimate that this carbon sink could sequester up to 2,171 Megatons (Mt) of CO 2 . [ABSTRACT FROM AUTHOR]

A comprehensive risk-based monitoring assessment methodology is developed to (i) incorporate background data for thresholds and monitoring design, (ii) use stochastic leakage simulations and monitoring modeling for risk scenarios given uncertainty, (iii) apply statistical methods to combine multiple monitoring techniques and provide decision support for evaluating proposed monitoring plans, and (iv) facilitate implementation in the National Risk Assessment Partnership (NRAP) integrated assessment model (IAM) framework. This methodology is illustrated using a case representative of the High Plains aquifer, considering the stochastic leakage events simulated using reactive transport simulations. The resulting groundwater quality changes were reflected in three groundwater monitoring parameters (pH, TDS and benzene concentrations), which were used to calculate the corresponding detection probability for each simulation, based on the background distributions and the selected thresholds. The consequent detection probability was then used to evaluate the monitoring well density and the proposed network designs. Beyond the detectability, the earliest response time and spatial coverage constraints of a monitoring network design are considered, and the role of adaptive monitoring strategies for compliance monitoring and incorporation of expert judgment on likely leakage locations is considered. [ABSTRACT FROM AUTHOR]

Deep underground geologic formations are being evaluated for long-term storage of CO 2 , including large continental flood basalt formations. At the GHGT-11 and GHGT-12 conferences, progress was reported on the initial phases for Wallula Basalt Pilot demonstration test (located in Eastern Washington state), where nearly 1,000 metric tons of CO 2 was injected over a 3-week period during July/August 2013. The target CO 2 injection intervals were two permeable basalt interflow reservoir zones with a combined thickness of ∼20 m that occur within a layered basalt sequence between a depth of 830-890 m below ground surface. During the two-year post-injection monitoring period, downhole fluid samples were periodically collected, coupled with limited wireline borehole logging surveys that provided indirect evidence of on-going chemical geochemical reactions/alterations and CO 2 distribution. A detailed pre-closure field characterization program included downhole fluid sampling, and performance of hydrologic tests and wireline geophysical surveys. Side-wall cores also were retrieved from within the targeted injection zones. Visual observations of the core material identified small globular nodules, translucent to yellow in color, residing within vugs and small cavities, which were not evident in pre-injection side-wall cores obtained from the native basalt formation. Characterization by x-ray diffraction identified these nodular precipitates as ankerite, the identical iron and calcium rich carbonate observed to form in laboratory tests with Columbia River basalts. Isotopic characterization (δ 13 C, δ 18 O) conducted on the ankerite nodules indicate a distinct isotopic signature that is closely aligned with that of the injected CO 2 . Final post-injection wireline geophysical logging results also indicate the presence of free-phase CO 2 at the top of the two injection interflow zones, with no vertical migration of CO 2 above the injection horizons. These findings support previous assumptions regarding storage feasibility and rapid mineralization of CO 2 injected into a suitable basalt formation. [ABSTRACT FROM AUTHOR]

Defining the ideal suite of monitoring technologies to be deployed at a carbon capture and storage (CCS) site presents a challenge to project developers, financers, insurers, regulators and other stakeholders. The monitoring, verification, and accounting (MVA) toolkit offers a suite of technologies to monitor an extensive range of parameters across a wide span of spatial and temporal resolutions, each with their own degree of sensitivity to changes in the parameter being monitored. Understanding how best to optimize MVA budgets to minimize the time to leak detection could help to address issues around project risks, and in turn help support broad CCS deployment. This paper presents a case study demonstrating an application of the Designs for Risk Evaluation and Management (DREAM) tool using an ensemble of CO 2 leakage scenarios taken from a previous study on leakage impacts to groundwater. Impacts were assessed and monitored as a function of pH, total dissolved solids (TDS), and trace metal concentrations of arsenic (As), cadmium (Cd), chromium (Cr), and lead (Pb). Using output from the previous study, the DREAM tool was used to optimize monitoring system designs based on variable sampling locations and parameters. The algorithm requires the user to define a finite budget to limit the number of monitoring wells and technologies deployed, and then iterates well placement, sensor type and location until it converges on the configuration with the lowest time to first detection of the leak averaged across all scenarios. To facilitate an understanding of the optimal number of sampling wells, DREAM was used to assess the marginal utility of additional sampling locations. Based on assumptions about monitoring costs and replacement costs of degraded water, the incremental cost of each additional sampling well can be compared against its marginal value in terms of avoided aquifer degradation. Applying this method, DREAM identified the most cost-effective ensemble with 14 monitoring locations. While this preliminary study applied relatively simplistic cost and technology assumptions, it provides an exciting proof-of-concept for the application of DREAM to questions of cost-optimized MVA system design that are informed not only by site-specific costs and technology options, but also by reservoir simulation results developed during site characterization and operation. [ABSTRACT FROM AUTHOR]

India is a coal rich nation and has significant volumes of coalbed methane reserves. The recent developments in CBM production show a positive way of further research on understanding the reservoir behavior for carbon sequestration. India has the 3rd largest proven coal reserves and is the 4th largest producer of coal in the world. Moreover, the estimated CBM resources hold significant prospects for commercial recovery of the natural gas. The total CBM resource in India has been estimated to be around 4.6 TCM. Deeper reserves from which recovery of coal after CBM extraction seems less feasible, technologically as well as economically, may be the prime targets for sequestration of anthropogenic CO 2 . Coal seams that are found at depths which are below the limits of mining are considered suitable for disposal of anthropogenic CO 2 . Some estimates suggest that huge CO 2 storage potential exists in the major coal fields in India and coal at depths more than 1200 m could store CO 2 in the order of 345 Mt. Power sector in India is mostly coal based and produce huge quantities of CO 2 . There are several industries acting as point sources for CO 2 . The close proximity of deeper coals and location of large point sources of CO 2 emission indicate the positives of sequestration in coal. Some basins have been marked with high sequestration potential of 1885 Mt in the Cambay basin while some like Singrauli could offer only 1-2 Mt of storage depending on various parameters. This study is a review of recent developments in the area of coal seam sequestration in India. A detailed analysis of the available literature was conducted along with few experiments on CO 2 -coal interactions. Few studies have been initiated in India to study the behaviour of Indian coal using CO 2 and also to explore the possibility of enhanced recovery of coalbed methane. The trapping of CO 2 in the coal seams is related to its capacity as well as the gas injectivity. Coal matrix shrinkage, swelling, gas diffusion and permeability have been significantly investigated over past few years. An important aspect which is yet to be fully understood is the role of phase transformation of CO 2 on its hydro-mechanical behavior. Few experiments were conducted in our laboratory using different phases of CO 2 in coal, obtained by varying pressure and temperature conditions. The changes in coal permeability due to supercritical CO 2 flow were greatly attributed to the high volumetric deformation or the swelling of coal under supercritical CO 2 as compared to liquid CO 2 . The injection pressures were observed to reduce the effective stress behavior, which in turn pushed the permeability evolution at each confinement to a positive trend. However, the permeability of CO 2 reduced exponentially with increasing effective stresses. [ABSTRACT FROM AUTHOR]

A significant amount of Carbon (C) on global soils consists of black carbon or charred organic matter. Biochar amendment in soils is therefore seen as a potential geoengineering method for climate change mitigation and adaptation. We tested the effects of biochar amendment (10 t.ha -1 ) on soil respiration trace a potential priming effect until 15 months after amendment. Our results indicate that after a short period of initially weak positive priming, there was no significant difference between control and biochar plots during the entire project duration. From a carbon sequestration point of view, it can be concluded, that biochar amendment leads to higher stable C stocks in the organic horizon. [ABSTRACT FROM AUTHOR]

The proliferation of commercial development in U.S. gas-bearing shales helped to drive a twelve-fold increase in domestic gas production between 2000 and 2010, and the nation's gas production rates continue to grow. While shales have long been regarded as a desirable caprock for CCS operations because of their low permeability and porosity, there is increasing interest in the feasibility of injecting CO 2 into shales to enhance methane recovery and augment CO 2 storage. Laboratory work published in recent years observes that shales with adsorbed methane appear to exhibit a stronger affinity for CO 2 adsorption, offering the potential to drive additional CH 4 recovery beyond primary production and perhaps the potential to store a larger volume of CO 2 than the volume of methane displaced. Recent research by the authors on the revenues associated with CO 2 -enhanced gas recovery (CO 2 -EGR) in gas-bearing shales estimates that, based on a range of EGR response rates, the average revenue per ton of CO 2 for projects managed over both EGR and subsequent storage-only phases could range from $0.50 to $18/tCO 2 . While perhaps not as profitable as EOR, for regions where lower-cost storage options may be limited, shales could represent another “early opportunity” storage option if proven feasible for reliable EGR and CO 2 storage. Significant storage potential exists in gas shales, with theoretical CO 2 storage resources estimated at approximately 30-50 GtCO 2 . However, an analysis of the comprehensive cost competitiveness of these various options is necessary to understand the degree to which they might meaningfully impact U.S. CCS deployment or costs. This preliminary analysis shows that the degree to which EGR-based CO 2 storage could play a role in commercial-scale deployment is heavily dependent upon the offsetting revenues associated with incremental recovery; modeling the low revenue case resulted in only five shale-based projects, while under the high revenue case, shales accounted for as much as 20 percent of total U.S. storage in the first 20 years of deployment. Interestingly, even in this highest revenue case, there appear to be no negative-cost projects that would be profitable in a no-policy environment as modeled under the assumptions employed. While this reflects a very first look at the potential for shales, it is clear that more laboratory and experimental work are needed to reduce uncertainty in key variables and begin to differentiate and identify high-potential shales for early pilot study. [ABSTRACT FROM AUTHOR]

The FutureGen 2.0 Project will design and build a first-of-its-kind, near-zero emissions coal-fueled power plant with carbon capture and storage (CCS). To assess storage site performance and meet the regulatory requirements of the Class VI Underground Injection Control (UIC) Program for CO 2 Geologic Sequestration, the FutureGen 2.0 project will implement a suite of monitoring technologies designed to evaluate CO 2 mass balance and detect any unforeseen loss in CO 2 containment. The monitoring program will include direct monitoring of the reservoir, and early-leak-detection monitoring directly above the primary confining zone. This preliminary modeling study described here focuses on hypothetical leakage scenarios into the first permeable unit above the primary confining zone (Ironton Sandstone) and is used to support assessment of early-leak detection capabilities. Future updates of the model will be used to assess potential impacts on the lowermost underground source of drinking water (Saint Peter Sandstone) for a range of theoretical leakage scenarios. This preliminary modeling evaluation considers both pressure response and geochemical signals in the overlying Ironton Sandstone. This model is independent of the FutureGen 2.0 reservoir model in that it does not simulate caprock discontinuities, faults, or failure scenarios. Instead this modeling effort is based on theoretical, volumetric-rate based leakage scenarios. The scenarios include leakage of 1% of the total injected CO 2 mass, but spread out over different time periods (20, 100, and 500 years) with each case yielding a different mass flux (i.e., smaller mass fluxes for longer duration leakage cases]. A brine leakage scenario using a volumetric leakage similar to the 20 year 1% CO 2 case was also considered. A framework for the comparison of the various cases was developed based on the exceedance of selected pressure and geochemical thresholds at different distances from the point of leakage and at different vertical positions within the Ironton Sandstone. These preliminary results, and results from an updated models that incorporate additional site-specific characterization data, support development/refinement of the monitoring system design. [ABSTRACT FROM AUTHOR]

The FutureGen 2.0 Project will design and build a first-of-its-kind, near-zero emissions coal-fueled power plant with carbon capture and storage (CCS). To assess storage site performance and meet the regulatory requirements of the Class VI Underground Injection Control (UIC) Program for CO 2 Geologic Sequestration, the FutureGen 2.0 project will implement a suite of monitoring technologies designed to 1) evaluate CO 2 mass balance and 2) detect any unforeseen loss in CO 2 containment. The monitoring program will include direct monitoring of the injection stream and reservoir, and early-leak-detection monitoring directly above the primary confining zone. It will also implement an adaptive monitoring strategy whereby monitoring results are continually evaluated and the monitoring network is modified as required, including the option to drill additional wells in out-years. Wells will be monitored for changes in CO 2 concentration and formation pressure, and other geochemical/isotopic signatures that provide indication of CO 2 or brine leakage. Indirect geophysical monitoring technologies that were selected for implementation include passive seismic, integrated surface deformation, time-lapse gravity, and pulsed neutron capture logging. Near-surface monitoring approaches that have been initiated include surficial aquifer and surface- water monitoring, soil-gas monitoring, atmospheric monitoring, and hyperspectral data acquisition for assessment of vegetation conditions. Initially, only the collection of baseline data sets is planned; the need for additional near- surface monitoring will be continually evaluated throughout the design and operational phases of the project, and selected approaches may be reinstituted if conditions warrant. Given the current conceptual understanding of the subsurface environment, early and appreciable impacts to near-surface environments are not expected. [ABSTRACT FROM AUTHOR]

The U.S. Department of Energy's (DOE's) National Risk Assessment Partnership (NRAP) Project is developing reduced-order models to evaluate potential impacts on underground sources of drinking water (USDWs) if CO 2 or brine leaks from deep CO 2 storage reservoirs. Threshold values, below which there would be no predicted impacts, were determined for portions of two aquifer systems. These threshold values were calculated using an interwell approach for determining background groundwater concentrations that is an adaptation of methods described in the U.S. Environmental Protection Agency's Unified Guidance for Statistical Analysis of Groundwater Monitoring Data at RCRA Facilities [1] . [ABSTRACT FROM AUTHOR]

Carbon stable isotopes can be used in characterization and monitoring of CO 2 sequestration sites to track the migration of the CO 2 plume and identify leakage sources, and to evaluate the chemical reactions that take place in the CO 2 -water-rock system. However, there are few tools available to incorporate stable isotope information into flow and transport codes used for CO 2 sequestration problems. We present a numerical tool for modeling the transport of stable carbon isotopes in multiphase reactive systems relevant to geologic carbon sequestration. The code is an extension of the reactive transport code TOUGHREACT. The transport module of TOUGHREACT was modified to include separate isotopic species of CO 2 gas and dissolved inorganic carbon (CO 2 , CO3, HCO3,…). Any process of transport or reaction influencing a given carbon species also influences its isotopic ratio. Isotopic fractionation is thus fully integrated within the dynamic system. The chemical module and database have been expanded to include isotopic exchange and fractionation between the carbon species in both gas and aqueous phases. The performance of the code is verified by modeling ideal systems and comparing with theoretical results. Efforts are also made to fit field data from the Pembina CO 2 injection project in Canada. We show that the exchange of carbon isotopes between dissolved and gaseous carbon species combined with fluid flow and transport, produce isotopic effects that are significantly different from simple two-component mixing. These effects are important for understanding the isotopic variations observed in field demonstrations. [ABSTRACT FROM AUTHOR]

Large-scale pressure increases resulting from carbon dioxide (CO 2 ) injection in the subsurface can potentially impact caprock integrity, induce reactivation of critically stressed faults, and drive CO 2 or brine through conductive features into shallow groundwater. Pressure management involving the extraction of native fluids from storage formations can be used to minimize pressure increases while maximizing CO 2 storage. However, brine extraction requires pumping, transportation, possibly treatment, and disposal of substantial volumes of extracted brackish or saline water, all of which can be technically challenging and expensive. This paper describes a constrained differential evolution (CDE) algorithm for optimal well placement and injection/extraction control with the goal of minimizing brine extraction while achieving predefined pressure contraints. The CDE methodology was tested for a simple optimization problem whose solution can be partially obtained with a gradient-based optimization methodology. The CDE successfully estimated the true global optimum for both extraction well location and extraction rate, needed for the test problem. A more complex example application of the developed strategy was also presented for a hypothetical CO 2 storage scenario in a heterogeneous reservoir consisting of a critically stressed fault nearby an injection zone. Through the CDE optimization algorithm coupled to a numerical vertically-averaged reservoir model, we successfully estimated optimal rates and locations for CO 2 injection and brine extraction wells while simultaneously satisfying multiple pressure buildup constraints to avoid fault activation and caprock fracturing. The study shows that the CDE methodology is a very promising tool to solve also other optimization problems related to GCS, such as reducing ‘Area of Review’, monitoring design, reducing risk of leakage and increasing storage capacity and trapping. [ABSTRACT FROM AUTHOR]

Geomechanics Technologies has completed a detailed characterization study of the Wilmington Graben offshore Southern California area for large-scale CO 2 storage. This effort has included: an evaluation of existing wells in both State and Federal waters, field acquisition of about 175 km of new seismic data, new well drilling, development of integrated 3D geologic, geomechanics, and fluid flow models for the area. The geologic analysis indicates that more than 100 million tons of storage capacity is available within the Pliocene and Miocene formations in the Graben. Combined fluid flow and geomechanical analyses indicates that injection and storage can be conducted without significant risk for caprock fracturing or fault activation, if injection pressures are limited to below 110% of hydrostatic pressure. Numerical analysis of fluid migration indicates that injection into the Pliocene Formation at depths of 5000 feet would lead to undesireable vertical migration of the CO 2 plume. Recent well drilling however, indicates that deeper sand is present at depths exceeding 7000 feet, which could be viable for large volume storage. [ABSTRACT FROM AUTHOR]

This study focuses on developing a method to characterize and detect leakage of carbon dioxide from a geologic sequestration site using a Picarro gas analyser, and to systematically evaluate the robustness of detection ability and optimize the data acquisition parameters by testing under varying conditions at the Zero Emissions Research and Technology field site in Bozeman, MT. It was determined (1) both 12CO 2 or 13CO 2 measurements provide equally good leak detection ability, (2) wind speed and direction does not limit detection ability with a sampling height less than 30 cm, and (3) δ13C measurements did not provide a reliable method for leak detection with our data acquisition strategy. [ABSTRACT FROM AUTHOR]

Natural gas is considered a cleaner and lower-emission fuel than coal, and its high abundance from advanced drilling techniques has positioned natural gas as a major alternative energy source for the U.S. However, each ton of CO 2 emitted from any type of fossil fuel combustion will continue to increase global atmospheric concentrations. One unique approach to reducing anthropogenic CO 2 emissions involves coupling CO 2 based enhanced gas recovery (EGR) operations in depleted shale gas reservoirs with long-term CO 2 storage operations. In this paper, we report unique findings about the interactions between important shale minerals and sorbing gases (CH4 and CO 2 ) and associated economic consequences. Where enhanced condensation of CO 2 followed by desorption on clay surface is observed under supercritical conditions, a linear sorption profile emerges for CH4. Volumetric changes to montmorillonites occur during exposure to CO 2 . Theory-based simulations identify interactions with interlayer cations as energetically favorable for CO 2 intercalation. In contrast, experimental evidence suggests CH4 does not occupy the interlayer and has only the propensity for surface adsorption. Mixed CH4:CO 2 gas systems, where CH4 concentrations prevail, indicate preferential CO 2 sorption as determined by in situ infrared spectroscopy and X-ray diffraction techniques. Collectively, these laboratory studies combined with a cost-based economic analysis provide a basis for identifying favorable CO 2 -EOR opportunities in previously fractured shale gas reservoirs approaching final stages of primary gas production. Moreover, utilization of site-specific laboratory measurements in reservoir simulators provides insight into optimum injection strategies for maximizing CH4/CO 2 exchange rates to obtain peak natural gas production. [ABSTRACT FROM AUTHOR]

Development of the FutureGen geologic storage site in Morgan County Illinois is part of a larger project to design, build, and operate a commercial-scale carbon capture and storage (CCS) system capable of capturing, treating, and storing the CO 2 off-gas from an oxy-combustion coal-fueled power plant located in Meredosia, Illinois. The geological storage site is designed to capture approximately 1.1 million metric tons (Mt) of CO 2 each year. To support the selection and design of the site, a comprehensive characterization effort was conducted in order to acquire fundamental subsurface site specific information. These characterization activities included seismic surveys coring, geophysical wireline logging, hydrologic testing and geomechanical testing. The characterization results combined with pertinent research literature were used to build a conceptual model of the site, which in turn informed the development of computer models. Collectively this work supported both the design work and the permitting under the U.S. Environmental Protection Agency's class VI Underground Injection Control (UIC) permit process which was developed specifically for CO 2 injection. The detailed design of the injection wells and associated monitoring network were completed in early 2014 and in August 2014 the site received the first issued set of class VI UIC permits in the Unites States for the planned injection wells. [ABSTRACT FROM AUTHOR]

Pressure increases attendant with CO 2 injection into the subsurface drive many of the risk factors associated with commercial- scale CCS projects, impacting project costs and liabilities in a number of ways. The area of elevated pressure defines the area that must be characterized and monitored; pressure drives fluid flow out of the storage reservoir along higher-permeability pathways that might exist through the caprock into overlying aquifers or hydrocarbon reservoirs; and pressure drives geomechanical changes that could potentially impact subsurface infrastructure or the integrity of the storage system itself. Pressure also limits injectivity, which can increase capital costs associated with installing additional wells to meet a given target injection rate. The ability to mitigate pressure increases in storage reservoirs could have significant value to a CCS project, but these benefits are offset by the costs of the pressure mitigation technique itself. Of particular interest for CO 2 storage operators is the lifetime cost of implementing brine extraction at a CCS project site, and the relative value of benefits derived from the extraction process. This is expected to vary from site to site and from one implementation scenario to the next. Indeed, quantifying benefits against costs could allow operators to optimize their return on project investment by calculating the most effective scenario for pressure mitigation. This work builds on research recently submitted for publication by the authors examining the costs and benefits of brine extraction across operational scenarios to evaluate the effects of fluid extraction on injection rate to assess the cost effectiveness of several options for reducing the number of injection wells required. Modeling suggests that extracting at 90% of the volumetric equivalent of injection rate resulted in a 1.8% improvement in rate over a non-extraction base case; a four-fold increase in extraction rate results in a 7.6% increase in injection rate over the no-extraction base case. However, the practical impacts on capital costs suggest that this strategy is fiscally ineffective when evaluated solely on this metric, with extraction reducing injection well needs by only one per 56 (1x case) or one per 13 (4x case). [ABSTRACT FROM AUTHOR]

A comprehensive monitoring program will be needed in order to assess the effectiveness of carbon sequestration at the FutureGen 2.0 carbon capture and storage (CCS) field-site. Geophysical monitoring methods are sensitive to subsurface changes that result from injection of CO 2 and will be used for: (1) tracking the spatial extent of the free phase CO 2 plume, (2) monitoring advancement of the pressure front, (3) identifying or mapping areas where induced seismicity occurs, and (4) identifying and mapping regions of increased risk for brine or CO 2 leakage from the reservoir. Site-specific suitability and cost effectiveness were evaluated for a number of geophysical monitoring methods including: passive seismic monitoring, reflection seismic imaging, integrated surface deformation, time-lapse gravity, pulsed neutron capture logging, cross-borehole seismic, electrical resistivity tomography, magnetotellurics and controlled source electromagnetics. The results of this evaluation indicate that CO 2 injection monitoring using reflection seismic methods would likely be difficult at the FutureGen 2.0 site. Electrical methods also exhibited low sensitivity to the expected CO 2 saturation changes and would be affected by metallic infrastructure at the field site. Passive seismic, integrated surface deformation, time-lapse gravity, and pulsed neutron capture monitoring were selected for implementation as part of the FutureGen 2.0 storage site monitoring program. [ABSTRACT FROM AUTHOR]

GeoMechanics Technologies has completed a geomechanical caprock integrity analysis and risk assessment study funded through the US Department of Energy. The project included: a detailed review of historical caprock integrity problems experienced in the natural gas storage industry; advanced coupled transport flow modelling and geomechanical simulation of three large-scale potential geologic sequestration sites to estimate geomechanical effects from large-scale CO 2 injection; and development of a quantitative risk and decision analysis tool to assess caprock integrity risks. Historical data from gas storage operations and CO 2 sequestration projects suggest that leakage and containment incident risks are on the order of 10 -1 to 10 -2 , which is higher risk than some previous studies have suggested for CO 2 . Geomechanical analysis, as described herein, can be applied to quantify risks and to provide operating guidelines to reduce risks. The risk assessment tool developed for this project has been applied to five areas: The Wilmington Graben offshore Southern California, Kevin Dome in Montana, the Louden Field in Illinois, the Sleipner CO 2 sequestration operation in the North Sea, and the In Salah CO 2 sequestration operation in North Africa. Of these five, the Wilmington Graben setting represent the highest relative risk while the Kevin Dome setting represents the lowest relative risk. [ABSTRACT FROM AUTHOR]

The Midwest Regional Carbon Sequestration Partnership (MRCSP) is implementing a commercial-scale carbon capture and storage (CCS) project in multiple Silurian carbonate pinnacle reefs in northern Michigan that are in various phases of enhanced oil recovery. This paper presents analyses of five pressure fall-off tests performed sequentially during the injection of 166,000 tonnes of CO 2 into a Type-1 (depleted) reef which has undergone primary and secondary production. Bottom-hole pressures were monitored in the injection well and in two observation wells to record progressively increasing reservoir pressure during the injection period, which also included five fall-off tests. Pressure data were analyzed using combined history-matching and pressure derivative matching techniques implemented with a commercial well-test interpretation program, FAST WellTest™. The paper illustrates the challenges of consistently interpreting CO 2 injection fall-off tests under multi-phase flow with varying pressure conditions using a single-phase analytical model. This work is relevant to CO 2 sequestration in depleted oil reservoirs because regular fall-off testing is required under the U.S. Environmental Protection Agency's Underground Injection Control (UIC) Program for CO 2 geologic sequestration (75 FR 77230). [ABSTRACT FROM AUTHOR]

Numerical simulation is an invaluable analytical tool for scientists and engineers in making predictions about of the fate of carbon dioxide injected into deep geologic formations for long-term storage. Current numerical simulators for assessing storage in deep saline formations have capabilities for modeling strongly coupled processes involving multifluid flow, heat transfer, chemistry, and rock mechanics in geologic media. Except for moderate pressure conditions, numerical simulators for deep saline formations only require the tracking of two immiscible phases and a limited number of phase components, beyond those comprising the geochemical reactive system. The requirements for numerically simulating the utilization and storage of carbon dioxide in partially depleted petroleum reservoirs are more numerous than those for deep saline formations. The minimum number of immiscible phases increases to three, the number of phase components may easily increase fourfold, and the coupled processes of heat transfer, geochemistry, and geomechanics remain. Public and scientific confidence in the ability of numerical simulators used for carbon dioxide sequestration in deep saline formations has advanced via a natural progression of the simulators being proven against benchmark problems, code comparisons, laboratory-scale experiments, pilot-scale injections, and commercial-scale injections. This paper describes a new numerical simulator for the scientific investigation of carbon dioxide utilization and storage in partially depleted petroleum reservoirs, with an emphasis on its unique features for scientific investigations. The mathematical foundations of this new simulator for enhanced oil recovery are those of the simulators developed for carbon sequestration in deep saline reservoirs, altered to consider the increased number of potential phases and compositional aspects by considering the oil in the system. As a demonstration of the simulator, a numerical simulation of carbon dioxide utilization for enhanced oil recovery in the western section of the Farnsworth Unit, representing an early stage in the progression of numerical simulators for carbon utilization and storage in depleted oil reservoirs. [ABSTRACT FROM AUTHOR]

This paper is inspired by theory related to the water-food-energy-climate nexus and suggests a novel model, suited for analysing carbon sequestration in dry land agriculture using irrigation. The model is applied specifically to photovoltaic water pumping (PVWP) systems for irrigation of grasslands in China. We argue against the narrow approaches to analysing the water issue often found in literature and propose that carbon sequestration, energy security, food security together with local moisture recycling patterns should be included within the system boundary in order to make analyses of dry land agricultural activities more relevant and accurate. [ABSTRACT FROM AUTHOR]

Carbon Capture and Storage (CCS) is the process of extraction of carbon dioxide (CO2) from industrial and energy related sources, transport to storage locations and long-term isolation from the atmosphere. It is being considered as a bridging technology, with significant carbon mitigation potential, especially for large point sources such as coal power plants. The present study looks at the technical feasibility and economic viability of any such initiative in the Indian context by means of case studies of individual power plants. The incremental cost of electricity (COE) of the plants retrofitted with CCS has been estimated using the cost data on CCS components from literature as well as using the IECM (Integrated Environmental Control Model) software. The values of incremental COE and the cost of CO2 avoidance have been estimated as INR 2.2-2.6/kWh and INR 2600-3200 per tCO2, respectively. The costs are highly sensitive to the boiler efficiency and the heat rate of the base plant. The retrofitting of the CCS units in the existing coal plants in India is expected to reduce the net power output of the already inadequate power sector and increase the electricity generation cost substantially. Thus, it would be worthwhile to investigate the necessary and sufficient conditions under which the Indian power plants could graduate to the CCS technologies. [ABSTRACT FROM AUTHOR]

Abstract: The eddy covariance method is a micrometeorological technique for direct measurements of gas transport between the surface and the atmosphere. It is widely used for quantifying CO2 emission rates from natural, urban and agricultural ecosystems, including areas of agricultural carbon sequestration. In geological carbon capture, utilization and sequestration, emerging projects utilize eddy covariance to monitor large areas where CO2 may escape from the subsurface, to detect and quantify CO2 leakage, and to improve CO2 storage efficiency. This paper describes key principles of the method, main requirements, typical instrumentation and software, and educational resources particularly useful for carbon sequestration research. [Copyright &y& Elsevier]

Abstract: The advancement of carbon capture technology combined with carbon dioxide (CO2) enhanced oil recovery (EOR) holds the promise of reducing the carbon footprint of coal-fired power plants and other industrial sources, while at the same time boosting production of oil. CO2 injection in deep formations has a long track record. Tertiary EOR with CO2 has its origins in West Texas in the 1970's, when CO2 was first used at large scale at the SACROC field to produce stranded oil following primary and secondary production (water flooding). Because CO2 mixes with oil and changes oil properties, CO2 floods are effective at producing additional oil following water flooding. Carbon dioxide is a valuable commodity both because of its ability to stimulate oil production from depleted reservoirs, and because of the limited volumes of naturally-sourced CO2 in the U.S. Therefore, during large-scale commercial floods, CO2 that is produced with oil during EOR is separated, compressed and re-injected and recycled numerous times. Venting to the atmosphere is a rare event, quantifiable, and constitutes an insignificant fraction of the injected CO2. The CO2 purchased mass, net any venting during EOR activity is sequestered in the reservoir by a combination of capillary, solution and physical trapping mechanisms. Approximately 600 million metric tonnes of purchased CO2 have been utilized in the southwest U.S. Permian Basin (PB) alone, the rough equivalent of 30 years worth of CO2 from a half dozen medium-sized coal-fired power plants. Although CO2 EOR technology is mature in the U.S., many reservoir targets have not been flooded because of limited CO2 supply. Moreover, very large newly discovered EOR resources, known as “residual oil zones” (ROZs) occur in naturally water-flooded intervals below the oil-water contact in reservoirs that possess pore space containing immobile oil. ROZs are also now being documented in geologic settings without overlying conventional oil and gas accumulations. ROZ exploration and production using CO2 promises the supplemental capacity to accept very large volumes of CO2 in order to access and produce the remaining immobilized oil. Many existing EOR sites may be ideal for sequestration because they: 1) provide known traps that have held hydrocarbons over geologic time, 2) provide existing CO2 transportation and injection infrastructure, 3) occur in areas where the general public widely accepts injection projects, 4) provide CO2 commoditization capability for capturing companies, 5) facilitate management of underground CO2 plumes, 6) have proven reservoir injectivity, 7) may offer additional stacked storage potential, and, 8) are advantageous for monitoring because of available well infrastructure, experienced service company presence, and dense pre-injection data. Despite these advantages, in order to assure long-term containment of CO2 for atmospheric purposes and related CO2 reduction credits, the following best practices will ensure credit for captured and sequestered CO2: 1) demonstrate the appropriateness of the reservoir and existing wells for long term CO2 storage (integrity of the reservoir and seal, and identifying/remediating existing penetrations that are historically documented as the highest risk for unexpected pathways for CO2 to the surface), 2) evaluate well construction practices to ensure they are compatible with long-term exposure to low pH fluids (carbonic acid), 3) account for the net CO2 volumes stored- separately from the volumes purchased and recycled, and 4) demonstrate the long-term “permanence” of the CO2 plume in the subsurface through flood surveillance, monitoring and careful site closure. EOR provides a readily available pathway to large volume storage though oil production offsetting major capital costs of capture facility and pipeline construction, boosting public acceptance through experience and community benefits. Moreover, after completion of EOR operations, sequestration activities can be continued via maximizing CO2 storage in the depleted field, and by injection into qualified and associated brine formations. [Copyright &y& Elsevier]

Abstract: A major global research and development effort is underway to commercialize carbon capture and storage (CCS) as a method to mitigate climate change. Recent studies have shown the potential to couple CCS with geothermal energy extraction using supercritical CO2 (ScCO2) as the working fluid. In a geothermal reservoir, the working fluid produces electricity as a byproduct of the CCS process by mining heat out of a reservoir as it is circulated between injector and producer wells. While ScCO2 has lower heat capacity than water, its lower viscosity more than compensates by providing for greater fluid mobility. Furthermore, CO2 exhibits high expansivity and compressibility, which can both help reduce parasitic loads in fluid cycling. Given the high capital costs for developing the deep well infrastructure for geologic storage of CO2, the potential to simultaneously produce geothermal energy is an attractive method to offset some of the costs and added energy requirements for separating and transporting the waste CO2 stream. We present here the preliminary design and reservoir engineering associated with the development of direct-fired turbomachinery for pilot-scale deployment at the SECARB Cranfield Phase III CO2 Storage Project, in Cranfield, Mississippi, U.S.A. The pilot-scale deployment leverages the prior investment in the Cranfield Phase III research site, providing the first ever opportunity to acquire combined CO2 storage/geothermal energy extraction data necessary to address the uncertainties involved in this novel technique. At the SECARB Cranfield Site, our target reservoir, the Tuscaloosa Formation, lies at a depth of 3.0km, and an initial temperature of 127°C. A CO2 injector well and two existing observation wells are ideally suited for establishing a CO2 thermosiphon and monitoring the thermal and pressure evolution of the well-pair on a timescale that can help validate coupled models. It is hoped that this initial demonstration on a pre-commercial scale can accelerate commercialization of combined CCS/geothermal energy extraction by removing uncertainties in system modeling. [Copyright &y& Elsevier]

Abstract: FutureGen 2.0 site will be the first near-zero emission power plant with fully integrated long-term storage in a deep, non-potable saline aquifer in the United States. The proposed FutureGen 2.0 CO2 storage site is located in northeast Morgan County, Illinois, U.S.A., forty-eight kilometres from the Meredosia Energy Center where a large-scale oxy- combustion demonstration will be conducted. The demonstration will involve > 90% carbon capture, which will produce more than one million metric tons (MMT) of CO2 per year. The CO2 will be compressed at the power plant and transported via pipeline to the storage site. To examine CO2 storage potential of the site, a 1,467m characterization well (FGA#1) was completed in December 2011. The target injection zone for CO2 storage is in a zone of high permeability within the upper portion of the Mt. Simon Sandstone. Confining beds of the overlying Eau Claire Formation reach a thickness of 126 m. Characterization of the target injection zone and the overlying confining zone was based on wellbore data, cores, and geophysical logs, along with surface geophysical (2-D seismic profiles, magnetic and gravity), and structural data collected during the initial stage of the project. Based on this geological model, 3D simulations of CO2 injection and redistribution were conducted using STOMP-CO2, a multiphase flow and transport simulator. After this characterization stage, it appears that the injection site is a suitable geologic system for CO2 sequestration and that the injection zone is sufficient to receive up to 33 MMT of CO2 at a rate of 1.1 MMT/yr. [Copyright &y& Elsevier]

Abstract: One of the fundamental physical phenomena related to CO2 injection in subsurface brine-saturated formations is the dissolution-diffusion-convection process of CO2. The injected supercritical CO2 being less dense than brine settles beneath the formation seal. The overlying CO2-saturated brine is slightly heavier than brine itself thus a density- driven convective flow occurs which will enhance the dissolution rate of CO2, reduce time for solutal trapping and increase storage security. In this work experiments and simulations at the laboratory scale were performed to help inform studies at the reservoir scale. Experiments were conducted in transparent Hele-Shaw cells and the captured visual results of the convection phenomenon were used to validate the numerical simulations performed using STOMP simulator. Experiments are repeated with variations in permeability to vary the characteristic Rayleigh number. Corresponding two-phase simulations are compared with their equivalent time shots obtained from experimental imaging. The experimental and numerical results show fairly good agreement in terms of fingering characteristics (length, thickness, frequency) and global time scale. [Copyright &y& Elsevier]

Abstract: The U.S. Geological Survey is conducting a probabilistic national assessment of CO2 storage resources in ∼200 storage assessment units (SAUs), and must present results at basin, regional, and national scales. To calculate combined resources with correctly propagated uncertainty requires a probabilistic aggregation procedure in which correlations between SAUs are estimated. A comparison of single- and multiple-stage aggregation methods shows that the former better represents the varied geology within and between basins. Pairwise SAU correlation coefficients are estimated by geologists. If the matrix is not positive semi-definite, it is adjusted. Subsets of the matrix are extracted for basin or regional calculations. [Copyright &y& Elsevier]

Abstract: Effective targeting of funds and research efforts to reduce industrial CO2 emissions can benefit from quantitative analysis methods that assess and compare a variety of carbon sequestration technologies. We develop a general methodology and quantitative scoring system, and then apply it to the specific CCS technology of Geosequestration. Our results indicate that the most critical barriers to widespread commercial adoption of Geosequestration are not technology- or capacity-related, but instead relate to issues of public acceptance and economics. Our analysis suggests that geosequestration has a medium to high probability of success as a commercial-scale CO2 storage option. [Copyright &y& Elsevier]

Abstract: Leakage of brine or carbon dioxide (CO2) from geologic CO2 storage reservoirs will trigger numerous costs. We present the Leakage Impact Valuation (LIV) method, a systematic and thorough scenario-based approach to identify these costs, their drivers, and who incurs them across four potential leakage outcomes: 1) Leakage only; 2) leakage that interferes with a subsurface activity; 3) leakage that affects groundwater; and 4) leakage that reaches the surface. The LIV method is flexible and can be used to investigate a wide range of scenarios. The financial consequences of leakage estimated by the LIV method will be specific to the case study, because the consequences of leakage will vary across case studies due to differences geologic, institutional, and regulatory settings. [Copyright &y& Elsevier]

Abstract: We had investigated feasible measures to reduce CO2 emission and came to conclusion that introduction of new fuel such as hydrogen with near zero CO2 emission is required for achieving Japan''s commitment of 80% CO2 reduction by 2050. Under this background, we are proposing and aiming to realize “CO2 free hydrogen chain” utilizing Australian brown coal linked with CCS. In this chain, hydrogen produced from brown coal is liquefied and transported to Japan by liquid hydrogen carrier. We have conducted feasibility study of commercial scale “CO2 free hydrogen chain”, whose result shows the chain is technically and economically feasible. [Copyright &y& Elsevier]

Abstract: A systematic comparison and optimization of thermo-chemical hydrogen production processes with CO2 capture is performed. The process options include the resource type, the syngas production method and the hydrogen purification technology, including CO2 separation by ab- or adsorption or membrane processes. With regard to climate change mitigation, the removed CO2 can be compressed for storage. To analyze the competitiveness of different CO2 capture options and H2 process alternatives a consistent multi-objective optimization methodology combining energy-flow models with process integration techniques and economic and environmental evaluation is applied. The potential of efficient decarbonization in fossil and renewable H2 processes is highlighted. [Copyright &y& Elsevier]

Abstract: The assessment of the CO2 storage potential in the Province of Québec, Canada, evaluates the four Paleozoic sedimentary basins present in the south of the province. The St. Lawrence Lowlands sub-basin represents by far the most prospective basin for CO2 storage. It contains excellent reservoir-seal pairs and several large CO2 emitters are present. The Anticosti sub-basin and the Magdalen basins are geologically prospective for CO2 storage, but infrastructure and accessibility are poor due to their offshore setting and large CO2 emitters are located far away. The prospectivity of the Appalachian and Gaspé Belt basins for CO2 storage is evaluated as very low, except for the northeastern part of the Gaspé Peninsula which offers more potential. [Copyright &y& Elsevier]

Abstract: Old wells could be exposed to severe environment. This study reports the characterization of a class G oilwell cement paste exposed to a brine at high pressure and high temperature.The results showed that pressure had a strong impact on the phenomenology and the kinetics of oilwell cement paste degradation in selected downhole conditions. The alteration mechanism at high pressure appears to be more complex than the one observed at atmospheric pressure. At atmospheric pressure the diffusion rate governs the kinetics and thus is slower than the rate of the chemical reaction. On the other hand, it seems that an increase of pressure increases much more the diffusion rate than the rate of reaction. Future developments are proposed in order to improve the understanding of the long-term behavior of oilwell cement paste at downhole conditions. [Copyright &y& Elsevier]

Abstract: Well integrity plays a key role in the overall performance of oil and gas projects, including Carbon Capture and Storage (CCS) projects. Well integrity has to be demonstrated over the well life-cycle, during operations (production, injection and/or monitoring), abandonment and few hundreds of years after closure, particularly to ensure effective CO2 confinement into the reservoir. To contribute to the development of CCS technologies at a commercial scale, a CO2 injection experiment was developed in Ketzin, Germany. The project included drilling three wells: one for CO2 injection, and two for CO2 monitoring. The COSMOS 2 R&D project included wellbore integrity evaluation through extensive modeling at a meso-scale (well components scale) and a macro scale (well scale). The modeling activities focused on the fluids migration from the reservoir along the wellbore taking into account ageing mechanisms (e.g. casing corrosion and cement leaching) and micro-annulus opening at cement/casing/rock interfaces due to thermo-mechanical stresses. Such modeling results have to be integrated in a pro-active risk-based management of well integrity in order to optimize design, define monitoring and maintenance action plan or demonstrate safety to authorities. The benefits are a good knowledge of the risks (causes and impacts), the assurance these are under control and, as a consequence, insurance of a secured investment. [Copyright &y& Elsevier]

Abstract: A potential CO2 seepage from sub-seabed storage may cause cascade effects in marine ecosystems if it influences a process that has a key-function in the complex ecosystem. Therefore not only the primary effects (CO2 increase and pH decreases) but also secondary effects (change in the mobility, and bioavailability of trace and heavy metals and organic toxins) should be studied. These impacts are still poorly understood. Here we present the preliminary results of an experimental study in a titanium pressure tank on the impact of CO2 seepage on trace elements mobility and bacterial composition at the sediment-water interface and some perspectives for future research. [Copyright &y& Elsevier]

Abstract: When a large volume of CO2 is injected into a geological formation this can lead to the mobilisation of substances of a chemical and physical nature. The purpose of this IEA GHG study[1] was to identify typical substances that could be mobilised during geosequestration and to evaluate potential tools for monitoring these substances. This project reviewed the scientific literature patent applications and industry publications relevant to the current monitoring of chemical and physical processes due to CO2-formation water-rock interactions from the deep subsurface through to the soil/water interface. Four major areas were identified for review: 1– physical effects, including pressure effects or displacement of fluids; 2 – geochemical effects, including dissolution of reservoir and seal rocks, as well as the potential for mobilisation of heavy metals; 3 – shallow/surface effects, potential nutrients/toxic compounds affecting soils and microbial communities, as well as groundwater quality; 4 –capture contaminant effects from coal fired plants and other point source emitters. The various processes have different degrees of impact in the three general monitoring domains: a) injection horizon (depleted hydrocarbon reservoir, saline formation), b) above-zone interval (zone directly overlying the seal of the storage interval), and c) shallow subsurface (potable groundwater aquifers, soil). Understanding these processes and mapping their distribution aids in the identification of potential monitoring tools and facilitates an assessment of their utility in a particular monitoring domain. Some tools already commonly deployed in other industries are highly applicable to the carbon storage industry; for example, downhole pressure gauges from the oil industry and water level loggers from the groundwater industry. In general, geophysical tools were found to be quite a mature method for identifying the presence of gas (hydrocarbons or CO2), but less so for observing mobilised substances and changes in salinity. Tools for measuring trace amounts of hydrocarbons in marine settings are able to be modified in order to be used for monitoring mobilised hydrocarbons entrained in capture emissions, from CO2/source rock interactions or ienhanced oil recovery processes, though many of the tools are not compound specific as yet. The aim of the project is to provide an understanding of the availability of conventional and novel tools for monitoring and verification (M&V) during CO2 injection. Some of these tools have been successfully employed in current carbon capture and storage (CCS) projects or in alternative applications, such as mineral exploration and ecological studies. [Copyright &y& Elsevier]

Abstract: Unlike other storage options, CO2 storage in coal seams is still in its infancy and requires advanced research to address the number of unknowns. One of the many questions that still need to be answered concerns the long term effects of storing CO2 in coal, specifically on the structure and properties of the coal. Most studies on coal structural changes have been conducted over a short period of adsorption (hours or 2-3 days) and at low pressures (1-20bar). Available literature has shown that the volumetric strains are a function of the local petrographic composition, and, in general, a coal''s response to CO2 sorption is based on the coal petrographic composition. The aim of this study was to determine any molecular structural and physical changes that may occur in coal following long term exposure (up to 6 months) to CO2 under subcritical conditions (up to 42bar). Inertinite-rich coal particles have a higher microporous surface area than vitrinite-rich particles of the same rank, as demonstrated by BET analysis. XRD results on the pre- and post-sorption coal samples demonstrated that CO2 sorption in coal causes some structural changes. The structural changes were found to be different for coals of different maceral composition, confirming the initial hypothesis. The coal samples that were exposed to CO2 over longer periods of time (6 months) displayed a more pronounced change in coal structure than those that were exposed for a shorter period of time (14 days). Volumetric sorption studies demonstrated that CO2 treated vitrinite-rich particles have a greater change in sorption properties than inertinite-rich particles. The study provides an insight into the chemical and physical changes caused by sorption of CO2 into coal, and could be used for modelling CO2-coal interactions, and for assisting in CO2-coal uptake calculations. [Copyright &y& Elsevier]

Abstract: The present renewed interest on CO2 EOR/EGR is led by an environmental concern. The consequence is that, today, we are urgently asked for considering the new CO2 EOR projects in association with CO2 storage. This implies an appropriate production well management allowing for delaying the CO2 breakthrough, while one has to keep a great concern on the safety issues related to the social acceptance, and to ensure a full economical viability of the CO2 injection projects. The picture becomes even more complex when it is planned to link various CO2 emission sites to various remote CO2 injection sites (typically already produced hydrocarbon reservoirs) through a large CO2 transportation infrastructure. In such a situation, it will be needed to harmonize in real time the rate fluctuations of the CO2 sources and the evolution of the CO2 sink injectivities (closely related to the reservoir pressure), while avoiding to meet the surface/transportation equipment limitations. The optimization of such a large system being not solvable rigorously, there is a particular interest towards methodologies allowing for a simplified reservoir modeling of the CO2 sinks (hydrocarbon field or aquifer). This point has been addressed in the work presented hereafter, which has been completed within the frame of the European ECCO project, aiming at providing a techno-economical tool for the CO2 value chain analysis. After a review of possible methods of reservoir conceptual modeling, the paper is presenting the approach followed for modeling reservoir CO2 EOR/EGR candidates in Central Europe. What is emphasized is the quantification of the impact of production constraints on hydrocarbon recovery and CO2 storage, in particular by means of an experimental design based tool. In addition, it is shown how some uncertainty on fluid miscible behavior can influence the hydrocarbon production. [Copyright &y& Elsevier]

Abstract: The major task of a safety surveillance concept is to support the closed loop of reservoir management, i.e. to guarantee an iterative interaction between reservoir monitoring and numerical simulation. The presented research is based on the experience gained on the permanent geoelectrical monitoring at the Ketzin CO2 pilot storage site continuously operating since 2007. We have structured this experience in a modular monitoring workflow which offers well prepared links to actual process data, petrophysical data, and reservoir simulation. First results have been reached in major topics such as site-specific customization of technical tools, data acquisition and processing, and data evaluation. Structuring this approach in a modular manner allows the geoelectric monitoring at the Ketzin site to be efficiently scaled up and adapted to the fit-for-purpose requirements of future CCS demonstrations. [Copyright &y& Elsevier]