Search

Injecting CO 2 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 alternative 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 CO 2 , (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. 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. [ABSTRACT FROM AUTHOR]

Abstract: Heterogeneities in porosity and permeability of geological CO2 storage reservoirs and surrounding strata have a significant influence on storage capacity, design of injection wells, CO2 injection rate, potential leakage, CO2 plume migration, and risk assessment. This study develops a methodology that applies a transition probability based Markov chain model to generate facies-based heterogeneous fields of reservoir and cap-rock porosity and permeability at the Rock Springs Uplift, Wyoming. This site was chosen for its proximity to the Jim Bridger power plant that generates 18Mt of CO2 per year. The heterogeneous fields are then used as input to simulations of CO2 injection in a numerical domain with geologic strata based on a 3D seismic model. We next use the multiphase flow simulator FEHM in Monte Carlo mode to generate 42 realizations of injection into the Weber sandstone. The model is constrained by two requirements. First, the effects of storage must be contained in the 16×16km working footprint (i.e. the injection pressure pulse and CO2 plume are not allowed to expand beyond the simulation domain) and second, injection pressures must not exceed 75% of the lithostatic load to limit seismic risks. Analysis of simulation results reveals that: (1) CO2 storage capacity for the Weber formation in the entire Rock Springs Uplift is 6614±256Mt at 95% confidence interval, about 36% of a previous estimate based on homogeneous and isotropic properties; (2) single well CO2 injection rates vary with time and with local permeability distributions. The injectivity at the end of 50 years of injection follows a log normal distribution and reaches a mean of 0.43Mt/year with a range of 0.06–3.22Mt/year within two standard deviations (1σ =0.09Mt/year); and (3) CO2 leakage into the cap-rock (Chugwater formation) is limited to 0.8±3.4Mt over the 50 years of injection. In addition, brine production rates required to maintain pressure in the working footprint are of nearly equal volume to the injected CO2. Within the CO2 plume at this deep site, CO2 has density of greater than 80% of the ambient brine, indicating that the CO2 plume evolution will be controlled more by fluid pressure gradients than by buoyant flow. These results suggest that injection into the Weber sandstone in a single 16×16km working footprint on the Rock Springs Uplift could likely store the total CO2 output of the Jim Bridger power plant for approximately 35 years with less than 1% leakage into the cap-rock. This plan would require 26±3 injection wells with likely an equal number or more of brine production wells around the perimeter of the working footprint. Assuming wells at a cost of $6M each, this would add less than $1/tonne to the cost of the storage, a small fraction of current capture costs. Finally, brine production on the order of 1km3 is required to minimize the risk of geomechanical failure and ensure limited pressure perturbation outside the working footprint. [Copyright &y& Elsevier]

Abstract: We describe preliminary application of the CO2-PENS performance and risk analysis tool to a planned geologic CO2 sequestration demonstration project in the Rock Springs Uplift (RSU), located in south western Wyoming. We use data from the RSU to populate CO2-PENS, an evolving system-level modeling tool developed at Los Alamos National Laboratory. This tool has been designed to generate performance and risk assessment calculations for the geologic sequestration of carbon dioxide. Our approach follows Systems Analysis logic and includes estimates of uncertainty in model parameters and Monte-Carlo simulations that lead to probabilistic results. Probabilistic results provide decision makers with a range in the likelihood of different outcomes. Herein we present results from a newly implemented approach in CO2-PENS that captures site-specific spatially coherent details such as topography on the reservoir/cap-rock interface, changes in saturation and pressure during injection, and dip on overlying aquifers that may be impacted by leakage upward through wellbores and faults. We present simulations of CO2 injection under different uncertainty distributions for hypothetical leaking wells and faults. Although results are preliminary and to be used only for demonstration of the approach, future results of the risk analysis will form the basis for a discussion on methods to reduce uncertainty in the risk calculations. Additionally, we present ideas on using the model to help locate monitoring equipment to detect potential leaks. By maintaining site-specific details in the CO2-PENS analysis we provide a tool that allows more logical presentations to stakeholders in the region. [Copyright &y& Elsevier]

Abstract: The Wyoming State Geological Survey has completed a thorough inventory and prioritization of all Wyoming stratigraphic units and geologic sites capable of sequestering commercial quantities of CO2 (5–15 Mt CO2/year). This multi-year study identified the Paleozoic Tensleep/Weber Sandstone and Madison Limestone (and stratigraphic equivalent units) as the leading clastic and carbonate reservoir candidates for commercial-scale geological CO2 sequestration in Wyoming. This conclusion was based on unit thickness, overlying low permeability lithofacies, reservoir storage and continuity properties, regional distribution patterns, formation fluid chemistry characteristics, and preliminary fluid-flow modeling. This study also identified the Rock Springs Uplift in southwestern Wyoming as the most promising geological CO2 sequestration site in Wyoming and probably in any Rocky Mountain basin. The results of the WSGS CO2 geological sequestration inventory led the agency and colleagues at the UW School of Energy Resources Carbon Management Institute (CMI) to collect available geologic, petrophysical, geochemical, and geophysical data on the Rock Springs Uplift, and to build a regional 3-D geologic framework model of the Uplift. From the results of these tasks and using the FutureGen protocol, the WSGS showed that on the Rock Springs Uplift, the Weber Sandstone has sufficient pore space to sequester 18 billion tons (Gt) of CO2, and the Madison Limestone has sufficient pore space to sequester 8 Gt of CO2. [Copyright &y& Elsevier]

Abstract: We present results from the first stages of a detailed three dimensional analysis of the geologic CO2 sequestration potential of the Rock Springs Uplift (RSU), located in south-western Wyoming. This site is of particular interest because of the collocated 2.1 GW Jim Bridger coal burning power plant and the possibility of additional power plants being developed in the area to take advantage of the abundant coal reserves in the RSU region (i.e. the Southern California Edison CEPL project). The Rock Springs Uplift is a huge asymmetric dome structure with two superior target sequestration reservoirs located beneath a 1500 m thick sequence of Cretaceous shale. The target reservoirs, the Weber Sandstone and Madison Limestone, with thicknesses of greater than 200m and 75m respectively, are located at depths where pressures are well above the critical point of CO2. Seismic data reveal that the structure of the RSU creates an ideal trap for buoyant supercritical CO2. The target reservoirs currently contain high salinity sour brines (35,000-80,000 ppm) with little or no economic value. Reservoir continuity inferred from well logs and cores and high average measured porosity (10%) and permeability (10-75 md) led to initial screening estimates on the order of 26 billion tons of CO2 for the storage capacity of the structure. This paper focuses on calculations that will help to refine the initial capacity estimates through the use of high resolution multiphase numerical models. First we present an analysis using a system level simulator, CO2-PENS, to differentiate between two injection depths in the Weber on the basis of the costs associated with on-site drilling and pipelines for a range of permeabilities. The deeper site is analogous to the subsurface near the Jim Bridger Power Plant (JBPP), while the shallower site is analogous to the crest of the RSU. Results of this analysis show that deeper injection may be more cost effective. Next, we develop a 3-D computational hydrostratigraphic model and simulate injection of CO2 near the Jim Bridger Power Plant. Utilizing existing seismic and wellbore data, a geologic framework model has been created in EarthVision (i.e., 3D model building and visualization software). From this model, hydrostratigraphic units were extracted and a 3-D computational mesh for a 16×16 km section of the RSU structure was constructed. This model is used to simulate injection of 80% of the total CO2 emissions from the 2.1 GW JBPP (483 kg/s or 15 Mt/year) into the Weber formation for two cases. The first case assumes a very high permeability in the Weber and needs only one injection well, while the second case assumes a lower permeability and uses 9 injection wells. The major differences between these two examples are the amount of CO2 that dissolves into the formation brines and the areal extent of the resulting plumes. Because the low permeability case requires more injectors, the injected CO2 is exposed to a larger volume of reservoir rock and leads to a higher percentage of the total injected CO2 being dissolved in the formation water. The focused injection for the high permeability case leads to more CO2 remaining in the supercritical state and longer up-dip transport. Finally, both cases show that both diffusive and advective transport into the surrounding strata may significantly increase the storage potential of the RSU. [Copyright &y& Elsevier]