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This work presents a detailed supercritical CO₂ storage resource estimation for the stacked basalt reservoirs in the Grande Ronde Basalt of the Columbia River Basalt Group in eastern Washington and Oregon. The assessment aims to derisk the commercialization potential of geologic carbon storage in basalt by leveraging both structural and mineralization trapping of CO₂ in basalt. The structural closures formed by anticlinal ridges and synclinal valleys in Yakima Fold Belt are excellent physical traps to accommodate injected supercritical CO₂. Rigorous hydraulic testing, well logs and simulation results from the Wallula Basalt Pilot #1 well showed the occurrence of 17 suitablemore » permeable injection zones (up to 2,496 mD) intercalated with dense seals (~2.6E-10 mD) in the Grand Ronde Basalt. In addition, geochemical studies showed fast reactions between supercritical CO₂ and dissolved basalt minerals to form stable carbonates. In conclusion, our calculation indicates up to 40 gigatons (P90) of mineralization storage resources exist in the Grande Ronde Basalt reservoirs.« less

Meeting global and national net zero carbon emission targets will require geologic carbon disposal. The U.S. Department of Energy (DOE) has accordingly funded significant research in this area, including the Wyoming CarbonSAFE project at Dry Fork Station (DFS) in Campbell County, Wyoming. This work studied wettability on micro- and macro-scales, CO₂ storage potential, and the correlation between the two to support the Wyoming CarbonSAFE project’s subsurface assessment. During the study, a target formation’s wettability was found to affect how much CO₂ can be stored in a given formation. Here, in this study, representative rock samples were selected from the targetmore » storage formations— Lakota, Hulett, and Minnelusa—based on the heterogeneity of the lithology, permeability, and porosity of the respective formations. The rock samples are all fine-grained sandstone with variable cementation and bedding structure, including different scales of laminated bedding. The porosity and permeability vary within the range of 9.0–14.3% and 0.1–28.9 mD, respectively. These rock samples were prepared for the micro-scale wettability (contact angle measurement), macro-scale wettability (wettability index derived from unsteady-state flow characterization for the core plugs), and CO₂ storage evaluation. The macro-scale experiments suggested that wettability appeared to dominate the CO₂ storage potential performance during the drainage process, where less water-wet behavior promoted higher CO₂ storage potential. The micro-scale wettability tests showed that the rock samples at the studied reservoir conditions behaved water-wet and became more water-wet as pressure increased. This kind of wettability change discourages further CO₂ storage potential yet benefits the CO₂ residual trapping as the CO₂ injection proceeds for the studied area. The results allow the recommendation of the best reservoir candidate for storage based on wettability that affects CO₂ storage. The work presented in this study provides valuable insights into wettability’s effect on the CO₂ storage capacity and wettability’s importance when identifying the optimal CO₂ storage formation to meet the project’s goals.« less

Geological CO₂ sequestration in deep saline aquifers has been extendedly investigated to reach the goal of carbon neutral as large amount of CO₂ can be reduced in a short time. Here, this study investigates the feasibility of water-alternating-gas (WAG) injection and brine extraction on enhancing CO₂ storage in a target deep saline aquifer, Minnelusa Sandstone in the Powder River Basin (PRB) of Wyoming. An integrated numerical model is developed to account for four scenarios: (1) CO₂ continuous injection (CI) through one injection well, (2) WAG injection through one injection well, (3) CO₂ CI through one injection well and brine extractionmore » through one producer, (4) WAG injection through one injection well and brine extraction through one producer. Simulation results suggest that WAG injection and brine extraction corporately make it possible to enhance CO₂ injectivity while securing CO₂ storage safety. For instance, WAG injection considerably reduces structural trapping contribution while enhances dissolved and residual trapping contributions. As for brine extraction, it can decrease the maximum averaged reservoir pressure by 37% and 22% for CI and WAG injection, respectively. Besides, sensitive analyses of the operational parameters for the fourth scenarios are performed. Results reveal that, when the amount of total CO₂ injection has been predetermined, CO₂ injection time and rate within each period of WAG should be small whereas it is preferable to have large water injection time and rate. This is to secure desirable dissolved and residual trapping contributions (store CO₂ with safety). Sensitive degree results confirm that CO₂ injection rate, water injection time, and CO₂ injection time of WAG injection exhibit significant effects on CO₂ storage whereas the impacts of producer bottom-hole pressure (BHP), water injection rate, and CO₂-water injection time are relatively weaker. This study not only sheds light on achieving double-win goal: enhance CO₂ injectivity and store CO₂ with safety, but also can be a critical reference for other CO₂ storage in deep saline aquifers.« less

Integration of petrophysical and geological information is critical to simulation of subsurface carbon storage (GCS). In this sense, two depositional facies were identified from the core description and well-log interpretation, namely massive (MS) and cross-bedded (CB) facies groups. Additionally, pore-scale characteristics were studied by a combination of techniques, e.g. Nuclear Magnetic Resonance (NMR) and mercury intrusion capillary pressure (MICP). Scanning electron microscope (SEM) and petrographic analyses show that the pore structure is dominantly controlled by the depositional environment and dolomite cementation. NMR-T₂ distributions of MS and CB facies show triple and quadruple modes, respectively. In addition, MICP of high- andmore » low-permeability MS facies samples, and their CB facies group mixtures were collected. The MS sample pore-throat size distribution is uni-modal, while the triple-modal characteristic of the mixtures indicates heterogeneous pore structures at the sub-core scale for CB facies. The reliably estimates of porosity and permeability for both facies groups via NMR techniques and the MLR (Multiple Linear Regression) approach demonstrate the applicability of these techniques to eolian sandstone. Moreover, irreducible water saturation via the T₂-cutoff method correlates strongly with T_2LM instead of porosity. Finally, the rock quality index and flow zone indicator were calculated based on Combinable Magnetic Resonance (CMR) log interpretations. This provides direct connection to properties measured in the well. Four flow units were classified for both facies groups. Finally, results show that better reservoir quality with significant heterogeneities is observed in the CB facies. This study highlights the importance integrating multiscale petrophysical properties including facies, pore architecture and diagenesis analysis with core- to log-scale property characterization. The results herein validate our reservoir characterization and flow unit classification in eolian reservoirs.« less

Injecting CO₂ into deep geologic formations for permanent storage can potentially lead to leakage or induced seismicity if the overpressures exceed the fracture gradient or fault re-activation pressure. Strategies that remove reservoir fluids before or after injection may reduce these risks. But, even extensively characterized reservoirs can have substantial gaps in characterization necessary for developing optimal deterministic or even probabilistic pressure management strategies. The characterization data may not provide well-defined bounds or distributions of reservoir parameters or conditions (permeability, fault locations, fracture gradient, fault reactivation pressure). To assess the impact of these uncertainties, we present an approach for evaluating alternativemore » pressure management strategies based on their robustness of meeting project performance criteria. We quantify the robustness of alternative strategies against several criteria: (1) exceeding fault re-activation pressure, (2) failing to inject a desired quantity of CO₂, (3) exceeding a maximum quantity of extracted brine, and (4) failing to reach a desired extraction efficiency. Our approach allows nuances of competing and complimentary criteria to be quantitatively evaluated in a manner and in a level of detail not possible with optimization approaches. We illustrate the fundamentals of the approach on a simple one-dimensional analytical example using the Thiem equation. Here, we demonstrate the approach using a numerical flow and transport model with uncertain heterogeneous permeabilities using data and site characteristics from the Rock Springs Uplift Carbon Storage Site in southwestern Wyoming.« less

Carbon capture, utilization and storage (CCUS) seeks beneficial applications for CO₂ recovered from fossil fuel combustion. This study evaluated the potential for removing formation water to create additional storage capacity for CO₂, while simultaneously treating the produced water for beneficial use. Furthermore, the process would control pressures within the target formation, lessen the risk of caprock failure, and better control the movement of CO₂ within that formation. The project plans to highlight the method of using individual wells to produce formation water prior to injecting CO₂ as an efficient means of managing reservoir pressure. Because the pressure drawdown resulting frommore » pre-injection formation water production will inversely correlate with pressure buildup resulting from CO₂ injection, it can be proactively used to estimate CO₂ storage capacity and to plan well-field operations. The project studied the GreenGen site in Tianjin, China where Huaneng Corporation is capturing CO₂ at a coal fired IGCC power plant. Known as the Tianjin Enhanced Water Recovery (EWR) project, local rock units were evaluated for CO₂ storage potential and produced water treatment options were then developed. Average treatment cost for produced water with a cooling water treatment goal ranged from 2.27 to 2.96 US$/m³ (recovery 95.25%), and for a boiler water treatment goal ranged from 2.37 to 3.18 US$/m³ (recovery 92.78%). Importance analysis indicated that water quality parameters and transportation are significant cost factors as the injection-extraction system is managed over time. Our study found that in a broad sense, active reservoir management in the context of CCUS/EWR is technically feasible. In addition, criteria for evaluating suitable vs. unsuitable reservoir properties, reservoir storage (caprock) integrity, a recommended injection/withdrawal strategy and cost estimates for water treatment and reservoir management are proposed.« less