This paper presents probabilistic methods to estimate the quantity of carbon dioxide (CO2) that can be stored in a mature oil reservoir and analyzes the uncertainties associated with the estimation. This work uses data from the Farnsworth Field Unit (FWU), Ochiltree County, Texas, which is currently undergoing a tertiary recovery process. The input parameters are determined from seismic, core, and fluid analyses. The results of the estimation of the CO2 storage capacity of the reservoir are presented with both expectation curve and log probability plot. The expectation curve provides a range of possible outcomes such as the P90, P50, and P10. The deterministic value is calculated as the statistical mean of the storage capacity. The coefficient of variation and the uncertainty index, P10/P90, is used to analyze the overall uncertainty of the estimations. A relative impact plot is developed to analyze the sensitivity of the input parameters towards the total uncertainty and compared with Monte Carlo. In comparison to the Monte Carlo method, the results are practically the same. The probabilistic technique presented in this paper can be applied in different geological settings as well as other engineering applications.

Farnsworth Field Unit (FWU), a mature oilfield currently undergoing CO2-enhanced oil recovery (EOR) in the northeastern Texas panhandle, is the study area for an extensive project undertaken by the Southwest Regional Partnership on Carbon Sequestration (SWP). SWP is characterizing the field and monitoring and modeling injection and fluid flow processes with the intent of verifying storage of CO2 in a timeframe of 100–1000 years. Collection of a large set of data including logs, core, and 3D geophysical data has allowed us to build a detailed reservoir model that is well-grounded in observations from the field. This paper presents a geological description of the rocks comprising the reservoir that is a target for both oil production and CO2 storage, as well as the overlying units that make up the primary and secondary seals. Core descriptions and petrographic analyses were used to determine depositional setting, general lithofacies, and a diagenetic sequence for reservoir and caprock at FWU. The reservoir is in the Pennsylvanian-aged Morrow B sandstone, an incised valley fluvial deposit that is encased within marine shales. The Morrow B exhibits several lithofacies with distinct appearance as well as petrophysical characteristics. The lithofacies are typical of incised valley fluvial sequences and vary from a relatively coarse conglomerate base to an upper fine sandstone that grades into the overlying marine-dominated shales and mudstone/limestone cyclical sequences of the Thirteen Finger limestone. Observations ranging from field scale (seismic surveys, well logs) to microscopic (mercury porosimetry, petrographic microscopy, microprobe and isotope data) provide a rich set of data on which we have built our geological and reservoir models.

Leakage pathways through caprock lithologies for underground storage of CO2 and/or enhanced oil recovery (EOR) include intrusion into nano-pore mudstones, flow within fractures and faults, and larger-scale sedimentary heterogeneity (e.g., stacked channel deposits). To assess multiscale sealing integrity of the caprock system that overlies the Morrow B sandstone reservoir, Farnsworth Unit (FWU), Texas, USA, we combine pore-to-core observations, laboratory testing, well logging results, and noble gas analysis. A cluster analysis combining gamma ray, compressional slowness, and other logs was combined with caliper responses and triaxial rock mechanics testing to define eleven lithologic classes across the upper Morrow shale and Thirteen Finger limestone caprock units, with estimations of dynamic elastic moduli and fracture breakdown pressures (minimum horizontal stress gradients) for each class. Mercury porosimetry determinations of CO2 column heights in sealing formations yield values exceeding reservoir height. Noble gas profiles provide a “geologic time-integrated” assessment of fluid flow across the reservoir-caprock system, with Morrow B reservoir measurements consistent with decades-long EOR water-flooding, and upper Morrow shale and lower Thirteen Finger limestone values being consistent with long-term geohydrologic isolation. Together, these data suggest an excellent sealing capacity for the FWU and provide limits for injection pressure increases accompanying carbon storage activities.

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This article presents numerical simulations of CO2 storage mechanisms in the Pennsylvanian Upper Morrow sandstone reservoir, locally termed the Morrow B sandstone in the Farnsworth Unit (FWU) of Ochiltree County, Texas. The CO2 storage mechanisms considered in the study under a CO2 enhanced oil recovery (EOR) mode include structural-stratigraphic trapping, CO2 dissolution in formation water and oil, and residual trapping. The reservoir simulation model was constructed on the basis of field geophysical, geological, and engineering data such as three-dimensional surface seismic data, well logs, and fluid analysis. A representative fluid sampled from the reservoir was analyzed and used to tune the equation of state. A thermodynamic minimum miscible pressure was subsequently computed and compared to the experimental outcome. A history matched model was constructed and used as a baseline to determine the effects of different hypothetical injection strategies (that consider CO2 purchase, gas recycling, and mull drilling), water-alternating-gas (WAG) schemes, and variable salinity on CO2 storage. The simulation results showed that a significant amount of stored CO2 was dissolved in residual oil, contributing to enhanced oil recovery from the tertiary stage of the field operations. Supercritical-phase CO2 mass within the reservoir compared to CO2 dissolved in formation water was found to be dependent on the CO2 injection strategy. The residual trapping contribution was significant when hysteresis was considered. Pressure, volume of reservoir fluid present, caprock integrity, and optimized WAG injection strategies were significant parameters determining the long-term CO2 storage capacity within the FWU. Caprock integrity analyses showed that sealing units have excellent storage capacity with the potential to support column heights of up to 10000 ft. This work shows an improved strategy of maximizing CO2 storage within a depleted oil reservoir. The results from this study show that pressure changes within the reservoir should be continuously monitored to enhance CO2 storage. This study serves as a benchmark for future CO2-EOR projects in the Anadarko basin or geologically similar basins throughout the world.