Basalt formations represent one of the most attractive alternative geologic storage options due to their potential for rapid mineralization of carbon dioxide (CO2), widespread geographic distribution, and potentially large storage capacity. The CANstore project will address research gaps crucial to de-risking and demonstrating subsurface, commercial-scale CO2 storage in basalt, and provide critical information to key stakeholders and developers in California and Nevada seeking CO2 storage opportunities. The project will demonstrate the technoeconomic feasibility of safely and securely transporting at least 50 million metric tonnes of CO2 by pipeline from existing stationary sources in the region to an onshore potential basalt storage complex on the Modoc Plateau in Northeastern California.

The gas–water interface in Underground Hydrogen Storage (UHS) reservoirs creates the possibility that water will upcone to the well during hydrogen (H 2 ) withdrawal with detrimental impacts. We study the upconing of water to a hydrogen injection/withdrawal (I/W) well using both an analytical solution and numerical simulation. We carried out sensitivity analyses of the engineered properties (e.g., distance of well bottom to gas–water interface, withdrawal rate) and the intrinsic properties (e.g., reservoir permeability, porosity) of an idealized UHS system. Horizontal permeability is the main parameter controlling the height of upconing. Daily I/W cycles to some degree mitigate upconing because injection pushes down the gas–water interface. Sampling-based global sensitivity analyses show clearly that reservoirs with large horizontal permeability are preferred for avoiding upconing. Minimizing withdrawal rate and maximizing either the distance from well to gas–water interface or the length of the perforated well interval are important engineering controls to minimize upconing.

Migration of clay fines can be a concern when less saline fluids are injected into brine-saturated sandstone formations containing clays. If the salinity near fluid injection wells decreases below a critical value, the clay fines near the injection may detach, start migrating, and finally clog the pores. This effect can cause permeability decline near the well and may rapidly reduce the well injectivity. The focus of this work is on evaluating the impacts of clay fines migration on permeability decline in the field, using a numerical model and pressure buildup data collected during successive variable-rate water injections in a deep sandstone reservoir. The numerical model accounts for the mixing of low-salinity water with native brine and the migration of clay fines with the detachment and pore-clogging processes. The model interpretation of the pressure buildup data implies that the observed reduction in well injectivity is mainly associated with the clay fines migration and related pore clogging near the well. The model reasonably well represents the pressure buildup data during the injections. Our simulations demonstrate that the permeability near the well can rapidly decline within the first hour of injection. The measured pressure buildup in post-injection periods appears to decay more rapidly, compared to the simulation results of the model that assume irreversible permeability damage. This raises the question whether the permeability damage may be partly reversible near the well by backflow of brine after the injection of low-salinity water.

Between August 2012 and September 2014, about 114,000 metric tonnes of CO2 was captured from the coal-fired Plant Barry Power Station at Bucks Alabama and injected into the Paluxy Formation above the oil pool in the southeast unit of the Citronelle Oilfield. Various monitoring methods were deployed at land surface and in project wells to measure system performance, comply with permit requirements and test new and innovative monitoring tools. The monitoring program relied heavily on active seismic methods for subsurface imaging of geologic structure and time-lapse seismic techniques to track the CO2 migration in the injection interval. Both conventional geophone/hydrophone and fiber-optic based Distributed Acoustic Sensing (DAS) arrays were deployed and tested, allowing a side by side comparison of the equipment and techniques. Geophysical imaging of the subsurface was successful using DAS in the offset vertical seismic profile (OVSP) survey configuration. A high resolution OVSP image of the subsurface was obtained in 2014 with DAS, which exceeded project expectations in comparison to a lower resolution image obtained in 2012 using a conventional 80-level geophone array. A time-lapse image of the redistribution of CO2 after injection ended in September 2014 was obtained with two DAS OVSP surveys from June 2014 and December 2015, thus successfully demonstrating its proof-of-concept. Unfortunately, a pre-injection baseline survey with DAS, which was in its initial stage of technology development in 2012, did not have sufficient quality for use, making it difficult to interpret the acquired DAS time-lapse difference. Additional research in this area has since demonstrated the utility of time-lapse DAS OVSP. DAS data were also acquired during a cross-well seismic survey conducted in 2014. Unfortunately, the DAS technique was not success in the cross-well survey configuration because the system noise level was too high in the crosswell frequency output range (100-1200 Hz) of the piezoelectric source (increasing by a factor of ten compared to VSP frequency band). Additionally, the cross-well geometry causes sub-horizontal (broadside) incidence on the vertical DAS fiber cable, which is known to be problematic. Current research is focused on improving the DAS cable response to broadside acoustic energy. Time-lapse seismic surveys using commercially available conventional arrays were also acquired. In contrast to the DAS acquired data, the cross-well seismic results obtained with the conventional array was highly successful and clearly showed the CO2 remained in zone at the end of injection. Time-lapse differencing of the OSVP surveys acquired with the conventional arrays proved to be inconclusive. Changes in wellbore conditions between surveys and unavoidable changes in equipment (the array used for the baseline survey was retired) affected data quality, making it difficult to interpret the OVSP results.

Successful storage of large volumes of CO2 in the subsurface requires improved understanding of the state of-stress at and below reservoir depth in order to mitigate the hazards associated with storage integrity and induced seismicity. However, determining stress orientations and magnitudes at storage reservoir depths is technically challenging, both vertically and laterally away from a wellbore. State-of-the-art methods of stress field estimation require direct measurements through boreholes, but these are expensive, spatially sparse, and potentially compromised simply by virtue of drilling the borehole. Moreover, direct stress field measurements made in boreholes are insensitive to the stress field at distances larger than a few hundreds of meters from the well-bore and leave an open question as to what the stresses are at the depths that earthquakes occur. Widely used elasto-tectonic models have been developed to infer stresses over regions where no direct measurements are available, but these methods fail to quantify the uncertainty. Additionally, borehole-based measurements (using wireline density logs, dipole sonic logs, borehole imaging, hydraulic fracturing tests, and other stress indicators) can only confidently measure/infer the minimum principal stress and therefore, only certain components of the full stress tensor. While, work is underway to develop a borehole tool for full stress tensor measurement, this does not address temporal changes in the stress field due to injection. In this project we are developing methodologies to measure the in-situ principal stress in the deep subsurface through use of multiple, independent, but complementary seismic methods (i.e. interferometry, shear wave splitting, and focal mechanism inversion), laboratory verification, and development of theoretical frameworks. By leveraging existing regional and local datasets we are developing a set of diagnostic tools for determining the in-situ stress state with reduced uncertainty at and below reservoir depths (1.5-6 km). We will apply remote geophysical methods such as focal mechanism inversion and shear wave splitting measurements to estimate spatial and temporal changes in the stress orientation by analyzing waveform records of local seismic and microseismic events recorded over extended time periods during times of nearby active injection. These methods can provide broader spatial coverage by sampling a range of depths and distances from a well. Additionally, they provide in-situ measurements of the stress field that do not require drilling boreholes to reach the locations of interest. We will further address poorly understood uncertainties of these indirect measurements through quantitative analysis of the seismic datasets and integration with results from laboratory experiments on basement core samples. The existing regional and local datasets used in this project are catalogs of more than 24,000 relocated earthquakes from M~0 to M4.9 induced near active fluid disposal wells in Kansas and Oklahoma. Water disposal in the subsurface is used as a proxy for CO2 injection. Applying the virtual seismometer method (VSM) we obtain a refined model of the 3D earth structure directly around the microseismic events. We can also measure variation in focal mechanisms, allowing us to track changes in stress orientation. These focal mechanism solutions are also inverted for 4D estimates of the stress tensor. Preliminary results, in Kansas, from shear wave splitting analysis of this dataset indicate that the maximum principal stress orientation is generally aligned with the expected ENE direction.

Industrial-scale injection of CO2 into the subsurface increases the fluid pressure in the reservoir, which if not properly controlled can potentially lead to geomechanical damage (i.e., fracturing of the caprock or reactivation of faults) and subsequent CO2 leakage. Brine extraction is one approach for managing formation pressure, effective stress, and plume movement in response to CO2 injection. The management of the extracted brine can be expensive (i.e., due to transportation, treatment, disposal, or re-injection), with added cost to the carbon capture and sequestration (CCS); thus, minimizing the volume of extraction brine is of great importance to ensure that the economics of CCS are favorable. The main objective of this study is to demonstrate the use of adaptive optimization methods in the planning of brine extraction and to investigate how the quality of initial site characterization data and the use of newly acquired monitoring data (e.g. pressure at observation wells) impact the optimization performance. We apply an adaptive management approach that integrates monitoring, calibration, and optimization of brine extraction rates to achieve pre-defined pressure constraints. Our results show that reservoir pressure management can be extremely benefited by early and high frequency pressure monitoring during early injection times, especially for poor initial reservoir characterization. Low frequencies of model calibration and optimization with monitoring data may lead to optimization problems because either pressure buildup constraints are violated or excessively high extraction rates are proposed. The adaptive pressure management approach may constitute an effective tool to manage pressure buildup under uncertain reservoir conditions by minimizing the volumes of extracted brine while controlling pressure buildup.

Industrial scale injection of CO2 into the subsurface can result in significant fluid pressure increases, which can lead to potential environmental impacts such as caprock fracturing, fault activation and leakage into underground fresh water aquifers. Pressure management through brine extraction is an approach for managing formation pressure, effective stress, and plume movement in response to CO2 injection. However, the handling and management of the extracted brine has a cost that is added to carbon capture and sequestration (CCS) operations; therefore minimizing the extracted volume of brine can be of great importance. At the same time, economics of pressure management via brine extraction can be improved by treating the extracted high-salinity water and making it available for beneficial uses, for example as cooling water for power plants. In this paper, we introduce and demonstrate application of an adaptive reservoir management approach that optimizes extraction rates of reservoir brines for pressure control in an integrated optimization framework. Our approach will be tested during a brine extraction field experiment located in the southern United States, which is currently in the design and planning stages. The objective of the experiment is to evaluate the technical feasibility of managing subsurface pressures associated with large-scale CO2 injection volumes and to assess the cost and effectiveness of desalination technologies for saline waters containing high total dissolved solids (TDS). Our integrated adaptive management approach involves monitoring, model calibration, and optimization of brine extraction for pressure control. Based on measurements obtained during the injection phase and utilizing improved predictive models from repeated calibration, initial optimization calculations will be revised in regular intervals and the operating decisions for controlling and managing subsurface pressurization will be updated. In this paper, in preparation of the actual field demonstration, we investigate use of borehole measurements (i.e., pressure changes) and electromagnetic (EM) geophysical methods (i.e. salinity changes) in the adaptive management of the injection and brine extraction project. We also present a numerical exercise to investigate how the optimization performance is affected by the quality of initial site characterization data and by the frequency of dynamic model updates with newly acquired data during the injection. Our numerical study shows that more accurate initial reservoir characterization data reduce the risk of pressure buildup above a given maximum pressure because the optimization algorithm arrives at better estimates of initial extraction rates, which in turn results in better control of pressure during the overall injection times. Results also show that low frequencies of model calibration and optimization with the new data, especially at early injection periods, may lead to optimization problems, either because pressure buildup constraints are violated or excessively high extraction rates are proposed. These optimization problems can be eliminated if more frequent data collection and model calibration are conducted, especially at early injection times. Approaches such as adaptive pressure management may constitute an effective tool to manage pressure buildup under uncertain reservoir conditions by minimizing the brine extraction volumes while controlling pressure buildups. This will be demonstrated in the actual field study, with injection planned to start in early 2019.

Geologic carbon sequestration (GCS) is the process of injecting CO2 into deep subsurface rock formations such as into depleted oil and gas reservoirs or deep saline aquifers for long-term storage. Over the last decade, a number of field, laboratory, and modeling studies have been undertaken to assess the feasibility and safety of CO2 geologic storage, including their potential impact on shallow groundwater aquifers overlying target CO2 storage reservoirs. This chapter provides a review of the literature on the primary concerns to groundwater quality from GCS and practices to mitigate or avoid impacts to water. The review covers possible pathways by which CO2 can leak from GCS reservoirs, the potential hazards associated with leakage of dissolved CO2 into shallow groundwater, state-of-the-art monitoring strategies for CO2 leakage, and an overview of guidelines and regulations in the United States that seek to minimize potential impact. Several knowledge gaps and science needs still remain for understanding the impacts of large-scale deployment of GCS to groundwater including likely leakage scenarios, pathways and associated fluxes, key characteristics of aquifers that could make them vulnerable to degradation upon CO2 intrusion, and the development of reduced-order models and effective monitoring strategies for understanding and designing appropriate responses to CO2 leakage.

The Southeast Carbon Sequestration Partnership (SECARB) Anthropogenic Test became the first fully integrated carbon capture, transport, and storage project to successfully demonstrate non-endangerment towards the closure of a Alabama Department of Environmental Management (ADEM) underground injection control (UIC) permit. Despite being a state-issued UIC Class V experimental well permit, this permit contained many elements specific to geologic sequestration of CO2 included in the United States Environmental Protection Agency (EPA) regulations for Class VI wells. This paper will outline the permit structure and the steps taken to demonstrate non-endangerment for the first fully integrated Carbon Capture and Storage (CCS) project on a coal-fired power plant using advanced amines for CO2 capture. The SECARB Anthropogenic Test is a U.S. Department of Energy (DOE), Southern Company, and Electric Power Research Institute (EPRI) funded, Southern States Energy Board (SSEB) managed, project designed to demonstrate deep underground injection and containment of anthropogenic CO2 sourced from a 750 MW (net) coal -fired electric generating unit at Plant Barry, Alabama. From August 2012 to September 2014, a total of 114,104 metric tonnes of CO2 were captured and transported via a 12-mile pipeline from Alabama Power Company’s Plant Barry and successfully injected and stored in the upper Paluxy formation, a Lower Cretaceous sandstone unit, at the Denbury Onshore operated Citronelle Oil Field in Citronelle, Alabama. One CO2 injection well and three monitoring wells were drilled for this project. The initial Class V experimental technology UIC permit application was modified to include some Class VI permit requirements by the EPA to demonstrate protection of underground sources of drinking water (USDWs). These requirements included but were not limited to bottom to top cement coverage, a model-based Area of Review (AoR) determination with periodic updates, and a suite of Monitoring, Verification and Accounting (MVA) methods to track and monitor the CO2 plume migration and containment within the permitted injection zone. The UIC permit required extensive monitoring of the injected CO2 with objectives to create and sustain well integrity, assure safe CO2 injection operations, verify the location and migration of the CO2 plume, and monitor for any CO2 leakage. As such, a suite of technologies were applied and developed to demonstrate non-endangerment of underground sources of drinking water (USDW’s) and to ensure that CO2 does not migrate out of the intended storage zones. This involved several levels of monitoring: surface monitoring, shallow groundwater monitoring, and deep reservoir monitoring via commercially available and experimental MVA methods. Sufficient evidence was provided by the suite of monitoring efforts to indicate successful non-endangerment of USDWs at the Citronelle site. No CO2 release or build-up was detected using groundwater analysis, tracer detection, and soil CO2 flux monitoring to indicate any shallow or surficial leakage of CO2. Additionally, no evidence of gas saturation was observed within or above the confining zone, based on the results of time-lapse pulsed neutron capture logging. Cross-well seismic results show no negative velocity anomalies in or above the confining unit, which implies that there is no detectable leakage out of the injection zone. The associated models simulating the distribution of CO2 through the injected geological layers agreed with observed monitoring data, demonstrating confinement within the injected zone and confirming that the Citronelle Dome structure forms an ideal CO2 storage complex for the confinement of CO2 in the subsurface.

One of the risks that CO2 geological sequestration imposes on the environment is the impact of potential CO2/brine leakage on shallow groundwater. The reliability of reactive transport models predicting the response of groundwater to CO2 leakage depends on a thorough understanding of the relevant chemical processes and key parameters affecting dissolved CO2 transport and reaction. Such understanding can be provided by targeted field tests integrated with reactive transport modeling. A controlled-release field experiment was conducted in Mississippi to study the CO2-induced geochemical changes in a shallow sandy aquifer at about 50m depth. The field test involved a dipole system in which the groundwater was pumped from one well, saturated with CO2 at the pressure corresponding to the hydraulic pressure of the aquifer, and then re-injected into the same aquifer using a second well. Groundwater samples were collected for chemical analyses from four monitoring wells before, during and after the dissolved CO2 was injected. In this paper, we present reactive transport models used to interpret the observed changes in metal concentrations in these groundwater samples. A reasonable agreement between simulated and measured concentrations indicates that the chemical response in the aquifer can be interpreted using a conceptual model that encompasses two main features: (a) a fast-reacting but limited pool of reactive minerals that responds quickly to changes in pH and causes a pulse-like concentration change, and (b) a slow-reacting but essentially unlimited mineral pool that yields rising metal concentrations upon decreased groundwater velocities after pumping and injection stopped. During the injection, calcite dissolution and Ca-driven cation exchange reactions contribute to a sharp pulse in concentrations of Ca, Ba, Mg, Mn, K, Li, Na and Sr, whereas desorption reactions control a similar increase in Fe concentrations. After the injection and pumping stops and the groundwater flow rate decreases, the dissolution of relatively slow reacting minerals such as plagioclase drives the rising concentrations of alkali and alkaline earth metals observed at later stages of the test, whereas the dissolution of amorphous iron sulfide causes slowly increasing Fe concentrations.

The chemical composition of formation water and associated gases from the lower Cretaceous Paluxy Formation was determined using four different sampling methods at a characterization well in the Citronelle Oil Field, Alabama, as part of the Southeast Regional Carbon Sequestration Partnership (SECARB) Phase III Anthropogenic Test, which is an integrated carbon capture and storage project. In this study, formation water and gas samples were obtained from well D-9-8 #2 at Citronelle using gas lift, electric submersible pump, U-tube, and a downhole vacuum sampler (VS) and subjected to both field and laboratory analyses. Field chemical analyses included electrical conductivity, dissolved sulfide concentration, alkalinity, and pH; laboratory analyses included major, minor and trace elements, dissolved carbon, volatile fatty acids, free and dissolved gas species. The formation water obtained from this well is a Na–Ca–Cl-type brine with a salinity of about 200,000mg/L total dissolved solids. Differences were evident between sampling methodologies, particularly in pH, Fe and alkalinity. There was little gas in samples, and gas composition results were strongly influenced by sampling methods. The results of the comparison demonstrate the difficulty and importance of preserving volatile analytes in samples, with the VS and U-tube system performing most favorably in this aspect.

The dissolution of CO 2 in water leads to a pH decrease and a carbonate content increase in affected groundwater, which in turn can drive the mobilization of metals from sediments. The mechanisms of metal release postulated in various field and laboratory studies often differ. Drawing primarily on previously published results, we examine contrasting metal mobilization behaviors at two field tests and in one laboratory study, to investigate whether the same mechanisms could explain metal releases in these different experiments. Numerical modeling of the two field tests reveals that fast Ca‐driven cation exchange (from calcite dissolution) can explain the release of most major and trace metal cations at both sites, and their parallel concentration trends. The dissolution of other minerals reacting more slowly (superimposed on cation exchange) also contributes to metal release over longer time frames, but can be masked by fast ambient groundwater velocities. Therefore, the magnitude and extent of mobilization depends not only on metal‐mineral associations and sediment pH buffering characteristics, but also on groundwater flow rates, thus on the residence time of CO 2 ‐impacted groundwater relative to the rates of metal‐release reactions. Sequential leaching laboratory tests modeled using the same metal‐release concept as postulated from field experiments show that both field and laboratory data can be explained by the same processes. The reversibility of metal release upon CO 2 degassing by de‐pressurization is also explored using simple geochemical models, and shows that the sequestration of metals by resorption and re‐precipitation upon CO 2 exsolution is quite plausible and may warrant further attention. © 2015 Society of Chemical Industry and John Wiley & Sons, Ltd.

Understanding the impacts caused by injection of large volumes of CO2 in the deep subsurface necessitates a comprehensive monitoring strategy. While surface-based and other remote geophysical methods can provide information on the general morphology of a CO2 plume, verification of the geochemical conditions and validation of the remote sensing data requires measurements from boreholes that penetrate the storage formation. Unfortunately, the high cost of drilling deep wellbores and deploying instrumentation systems constrains the number of dedicated monitoring borings as well as limits the technologies that can be incorporated in a borehole completion. The objective of the Modular Borehole Monitoring (MBM) Program was to develop a robust suite of well-based tools optimized for subsurface monitoring of CO2 that could meet the needs of a comprehensive well-based monitoring program. It should have enough flexibility to be easily reconfigured for various reservoir geometries and geologies. The MBM Program sought to provide storage operators with a turn-key fully engineered design that incorporated key technologies, function over the decades long time-span necessary for post-closure reservoir monitoring, and meet industry acceptable risk profiles for deep-well installations.While still within the conceptual design phase of the MBM program, the SECARB Anthropogenic Test in Citronelle, Alabama, USA was identified as a deployment site for our engineered monitoring systems. The initial step in designing the Citronelle MBM system was to down-select from the various monitoring tools available to include technologies that we considered essential to any program. Monitoring methods selected included U-tube geochemical sampling, discrete quartz pressure and temperature gauges, an integrated fibre-optic bundle consisting of distributed temperature and heat-pulse sensing, and a sparse string of conventional 3C-geophones. While not originally planned within the initial MBM work scope, the fibre-optic cable was able to also be used for the emergent technology of distributed acoustic sensing. The MBM monitoring string was installed in March, 2012. To date, the Citronelle MBM instruments continue to operate reliably. Results and lessons learned from the Citronelle MBM deployment are addressed along with examples of data being collected. Published by Elsevier Ltd.

During a carbon sequestration field study to simulate the impact of CO2 migration on shallow groundwater chemistry, the isotope composition of dissolved inorganic carbon (delta C-13(DIC)) and dissolved strontium (Sr-87/Sr-86) were evaluated as tracers. Dissolved CO2 in groundwater was introduced using a closed-loop dipole-style well field situated in a shallow sand-dominated aquifer. Baseline delta C-13(DIC) values, oxygen and hydrogen isotope ratios, and Sr-87/Sr-86 values of groundwater were established in four monitoring wells (MW-1 to 4) and one up-gradient background well (BG-1) prior to the introduction of dissolved CO2. Baseline groundwater delta C-13(DIC-PDB), oxygen (delta O-18(SMOW)) and hydrogen (delta D-SMOW) stable isotope values averaged -17, -4.1 and -19.5 parts per thousand, respectively. Groundwater Sr-87/Sr-86 baseline values averaged 0.70840 at MW-3 and 0.70818 at MW-2. Arrival of the dissolved CO2 plume at the monitoring wells is modeled using a 1-D analytical equation, which yields breakthrough curves with flow velocities that are consistent with prior numerical modeling estimates. The delta C-13(DIC-PDB) rose to an average steady-state value of 0.16 +/- 0.3 parts per thousand during the test; delta O-18 and delta D of water did not change from their baseline values. Sr-87/Sr-86 dropped sharply by 0.00022 at MW-3 and 0.00005 at MW-2 in the first two weeks after plume arrival at the wells, and then slowly increased toward baseline values, correlating with the behavior of dissolved Na, K, Ca, Sr and Si. Carbonate dissolution and desorption from organic matter and Fe-bearing phases at the low-pH plume front is the likely mechanism producing this behavior. The delta C-13(DIC) and the Sr-87/Sr-86 of dissolved strontium served as excellent tracers of plume movement during this experiment. (C) 2014 Elsevier Ltd. All rights reserved.