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Forecasting CO₂ Sequestration with Enhanced Oil Recovery

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A special issue of Energies (ISSN 1996-1073). This special issue belongs to the section "H: Geo-Energy".

Deadline for manuscript submissions: closed (30 June 2021) | Viewed by 33323

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Special Issue Editors

Dr. William Ampomah

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Petroleum Recovery Research Center, New Mexico Institute of Mining and Technology, Socorro, NM, USA
Interests: reservoir characterization; simulation; optimization; enhanced oil recovery; CO₂ storage
Special Issues, Collections and Topics in MDPI journals

Prof. Dr. Brian McPherson

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Energy & Geoscience Institute (EGI), University of Utah, Salt Lake City, UT, USA
Interests: simulation; risk assessment; reactive transport
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Dr. Robert Balch

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Petroleum Recovery Research Center, New Mexico Institute of Mining and Technology, Socorro, NM, USA
Interests: reservoir characterization; MVA; CO₂ storage
Special Issues, Collections and Topics in MDPI journals

Dr. Reid Grigg

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Guest Editor

Petroleum Recovery Research Center, New Mexico Institute of Mining and Technology, Socorro, NM, USA
Interests: numerical modeling; enhanced oil recovery; risk assessment
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Martha Cather

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Guest Editor

Petroleum Recovery Research Center, New Mexico Insitute of Mining and Technology, Socorro, NM, USA
Interests: reservoir characterization; MVA; CO₂ storage
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

The aim of carbon capture, utilization, and storage (CCUS) is to reduce the amount of CO2 released into the atmosphere and to mitigate its effects on climate change. Over the years, naturally occurring CO2 sources have been utilized in enhanced oil recovery (EOR) projects in the United States. This has presented an opportunity to supplement and gradually replace the high demand for natural CO2 sources with anthropogenic sources. There also exist incentives for operators to become involved in the storage of anthropogenic CO2 within partially depleted reservoirs, besides the incremental produced oil revenues. These incentives include a wider availability of anthropogenic sources, the reduction of emissions to meet regulatory requirements, tax incentives in some jurisdictions, and favorable public relations.

The United States Department of Energy through its Carbon Storage program has sponsored several Regional Carbon Sequestration Partnerships (RCSPs) that have conducted field demonstrations for both EOR and saline aquifer storage. Various research efforts have been made in the area of reservoir characterization, monitoring, verification and accounting, simulation, and risk assessment to ascertain long-term storage potential within the subject storage complex. This Special Issue is a collection of lessons learned through the RCSP program within the Southwest Region of the United States. This Special Issue invites scientific output from the RSCP program on the following topics related to CCUS:

Reservoir characterization for CCUS;
Monitoring, verification, and accounting;
Advanced numerical simulation of CO₂-EOR and storage;
Risk Assessment of long-term CO₂ storage;

Dr. William Ampomah
Prof. Dr. Brian McPherson
Dr. Robert Balch
Dr. Reid Grigg
Ms. Martha Cather
Guest Editors

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Please visit the Instructions for Authors page before submitting a manuscript. The Article Processing Charge (APC) for publication in this open access journal is 2600 CHF (Swiss Francs). Submitted papers should be well formatted and use good English. Authors may use MDPI's English editing service prior to publication or during author revisions.

Keywords

reservoir characterization
enhanced oil recovery
CO₂ storage
co-optimization
numerical simulation
reactive transport
uncertainty quantification
CO₂ monitoring
time-lapse analysis

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Forecasting CO₂ Sequestration with Enhanced Oil Recovery II in Energies (9 articles)

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Editorial

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7 pages, 188 KiB

Open AccessEditorial

Forecasting CO₂ Sequestration with Enhanced Oil Recovery

by William Ampomah, Brian McPherson, Robert Balch, Reid Grigg and Martha Cather

Energies 2022, 15(16), 5930; https://doi.org/10.3390/en15165930 - 16 Aug 2022

Cited by 3 | Viewed by 1107

Abstract

Over the years, naturally occurring CO₂ has been used in many enhanced oil recovery (EOR) projects in the United States [...] Full article

(This article belongs to the Special Issue Forecasting CO₂ Sequestration with Enhanced Oil Recovery)

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24 pages, 3812 KiB

Open AccessArticle

Analysis of Geologic CO₂ Migration Pathways in Farnsworth Field, NW Anadarko Basin

by Jolante van Wijk, Noah Hobbs, Peter Rose, Michael Mella, Gary Axen and Evan Gragg

Energies 2021, 14(22), 7818; https://doi.org/10.3390/en14227818 - 22 Nov 2021

Cited by 5 | Viewed by 2465

Abstract

This study reports on analyses of natural, geologic CO₂ migration paths in Farnsworth Oil Field, northern Texas, where CO₂ was injected into the Pennsylvanian Morrow B reservoir as part of enhanced oil recovery and carbon sequestration efforts. We interpret 2D and 3D seismic reflection datasets of the study site, which is located on the western flank of the Anadarko basin, and compare our seismic interpretations with results from a tracer study. Petroleum system models are developed to understand the petroleum system and petroleum- and CO₂-migration pathways. We find no evidence of seismically resolvable faults in Farnsworth Field, but interpret a karst structure, erosional structures, and incised valleys. These interpretations are compared with results of a Morrow B well-to-well tracer study that suggests that inter-well flow is up-dip or lateral. Southeastward fluid flow is inhibited by dip direction, thinning, and draping of the Morrow B reservoir over a deeper, eroded formation. Petroleum system models predict a deep basin-ward increase in temperature and maturation of the source rocks. In the northwestern Anadarko Basin, petroleum migration was generally up-dip with local exceptions; the Morrow B sandstone was likely charged by formations both below and overlying the reservoir rock. Based on this analysis, we conclude that CO₂ escape in Farnsworth Field via geologic pathways such as tectonic faults is unlikely. Abandoned or aged wellbores remain a risk for CO₂ escape from the reservoir formation and deserve further monitoring and research. Full article

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19 pages, 10214 KiB

Open AccessArticle

Probabilistic Assessment and Uncertainty Analysis of CO₂ Storage Capacity of the Morrow B Sandstone—Farnsworth Field Unit

by Jonathan Asante, William Ampomah, Dylan Rose-Coss, Martha Cather and Robert Balch

Energies 2021, 14(22), 7765; https://doi.org/10.3390/en14227765 - 19 Nov 2021

Cited by 11 | Viewed by 2197

Abstract

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. Full article

(This article belongs to the Special Issue Forecasting CO₂ Sequestration with Enhanced Oil Recovery)

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26 pages, 5890 KiB

Open AccessArticle

Multiscale Assessment of Caprock Integrity for Geologic Carbon Storage in the Pennsylvanian Farnsworth Unit, Texas, USA

by Natasha Trujillo, Dylan Rose-Coss, Jason E. Heath, Thomas A. Dewers, William Ampomah, Peter S. Mozley and Martha Cather

Energies 2021, 14(18), 5824; https://doi.org/10.3390/en14185824 - 15 Sep 2021

Cited by 6 | Viewed by 2634

Abstract

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. Full article

(This article belongs to the Special Issue Forecasting CO₂ Sequestration with Enhanced Oil Recovery)

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24 pages, 21003 KiB

Open AccessArticle

Time-Lapse Integration at FWU: Fluids, Rock Physics, Numerical Model Integration, and Field Data Comparison

by Robert Will, Tom Bratton, William Ampomah, Samuel Acheampong, Martha Cather and Robert Balch

Energies 2021, 14(17), 5476; https://doi.org/10.3390/en14175476 - 02 Sep 2021

Cited by 6 | Viewed by 1917

Abstract

We present the current status of time-lapse seismic integration at the Farnsworth (FWU) CO₂ WAG (water-alternating-gas) EOR (Enhanced Oil Recovery) project at Ochiltree County, northwest Texas. As a potential carbon sequestration mechanism, CO₂ WAG projects will be subject to some degree of monitoring and verification, either as a regulatory requirement or to qualify for economic incentives. In order to evaluate the viability of time-lapse seismic as a monitoring method the Southwest Partnership (SWP) has conducted time-lapse seismic monitoring at FWU using the 3D Vertical Seismic Profiling (VSP) method. The efficacy of seismic time-lapse depends on a number of key factors, which vary widely from one application to another. Most important among these are the thermophysical properties of the original fluid in place and the displacing fluid, followed by the petrophysical properties of the rock matrix, which together determine the effective elastic properties of the rock fluid system. We present systematic analysis of fluid thermodynamics and resulting thermophysical properties, petrophysics and rock frame elastic properties, and elastic property modeling through fluid substitution using data collected at FWU. These analyses will be framed in realistic scenarios presented by the FWU CO₂ WAG development. The resulting fluid/rock physics models will be applied to output from the calibrated FWU compositional reservoir simulation model to forward model the time-lapse seismic response. Modeled results are compared with field time-lapse seismic measurements and strategies for numerical model feedback/update are discussed. While mechanical effects are neglected in the work presented here, complementary parallel studies are underway in which laboratory measurements are introduced to introduce stress dependence of matrix elastic moduli. Full article

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25 pages, 6106 KiB

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Numerical Modeling of CO₂ Sequestration within a Five-Spot Well Pattern in the Morrow B Sandstone of the Farnsworth Hydrocarbon Field: Comparison of the TOUGHREACT, STOMP-EOR, and GEM Simulators

by Eusebius J. Kutsienyo, Martin S. Appold, Mark D. White and William Ampomah

Energies 2021, 14(17), 5337; https://doi.org/10.3390/en14175337 - 27 Aug 2021

Cited by 5 | Viewed by 2136

Abstract

The objectives of this study were (1) to assess the fate and impact of CO₂ injected into the Morrow B Sandstone in the Farnsworth Unit (FWU) through numerical non-isothermal reactive transport modeling, and (2) to compare the performance of three major reactive solute transport simulators, TOUGHREACT, STOMP-EOR, and GEM, under the same input conditions. The models were based on a quarter of a five-spot well pattern where CO₂ was injected on a water-alternating-gas schedule for the first 25 years of the 1000 year simulation. The reservoir pore fluid consisted of water with or without petroleum. The results of the models have numerous broad similarities, such as the pattern of reservoir cooling caused by the injected fluids, a large initial pH drop followed by gradual pH neutralization, the long-term persistence of an immiscible CO₂ gas phase, the continuous dissolution of calcite, very small decreases in porosity, and the increasing importance over time of carbonate mineral CO₂ sequestration. The models differed in their predicted fluid pressure evolutions; amounts of mineral precipitation and dissolution; and distribution of CO₂ among immiscible gas, petroleum, formation water, and carbonate minerals. The results of the study show the usefulness of numerical simulations in identifying broad patterns of behavior associated with CO₂ injection, but also point to significant uncertainties in the numerical values of many model output parameters. Full article

(This article belongs to the Special Issue Forecasting CO₂ Sequestration with Enhanced Oil Recovery)

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32 pages, 18870 KiB

Open AccessArticle

Analysis of Caprock Tightness for CO₂ Enhanced Oil Recovery and Sequestration: Case Study of a Depleted Oil and Gas Reservoir in Dolomite, Poland

by Małgorzata Słota-Valim, Andrzej Gołąbek, Wiesław Szott and Krzysztof Sowiżdżał

Energies 2021, 14(11), 3065; https://doi.org/10.3390/en14113065 - 25 May 2021

Cited by 6 | Viewed by 2173

Abstract

This study addresses the problem of geological structure tightness for the purposes of enhanced oil recovery with CO₂ sequestration. For the first time in the history of Polish geological survey the advanced methods, practical assumptions, and quantitative results of detailed simulations were applied to study the geological structure of a domestic oil reservoir as a potential candidate for a combined enhanced oil recovery and CO₂ sequestration project. An analysis of the structure sequestration capacity and its tightness was performed using numerical methods that combined geomechanical and reservoir fluid flow modelling with a standard two-way coupling procedure. By applying the correlation between the geomechanical state and transport properties of the caprock, threshold pressure variations were determined to be a key factor affecting the sealing properties of the reservoir–caprock boundary. In addition to the estimation of the sequestration capacity of the structure, the process of CO₂ leakage from the reservoir to the caprock was simulated for scenarios exceeding the threshold pressure limit of the reservoir–caprock boundary. The long-term simulations resulted in a comprehensive assessment of the total amount of CO₂ leakage as a function of time and the leaked CO₂ distribution within the caprock. Full article

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17 pages, 25293 KiB

Open AccessFeature PaperArticle

A Gate-to-Gate Life Cycle Assessment for the CO₂-EOR Operations at Farnsworth Unit (FWU)

by Anthony Morgan, Reid Grigg and William Ampomah

Energies 2021, 14(9), 2499; https://doi.org/10.3390/en14092499 - 27 Apr 2021

Cited by 13 | Viewed by 2917

Abstract

Greenhouse gas (GHG) emissions related to the Farnsworth Unit’s (FWU) carbon dioxide enhanced oil recovery (CO₂-EOR) operations were accounted for through a gate-to-gate life cycle assessment (LCA) for a period of about 10 years, since start of injection to 2020, and predictions of 18 additional years of the CO₂-EOR operation were made. The CO₂ source for the FWU project has been 100% anthropogenically derived from the exhaust of an ethanol plant and a fertilizer plant. A cumulative amount of 5.25 × 10⁶ tonnes of oil has been recovered through the injection of 1.64 × 10⁶ tonnes of purchased CO₂, of which 92% was stored during the 10-year period. An LCA analysis conducted on the various unit emissions of the FWU process yielded a net negative (positive storage) of 1.31 × 10⁶ tonnes of CO₂ equivalent, representing 79% of purchased CO₂. An optimized 18-year forecasted analysis estimated 86% storage of the forecasted 3.21 × 10⁶ tonnes of purchased CO₂ with an equivalent 2.90 × 10⁶ tonnes of crude oil produced by 2038. Major contributors to emissions were flaring/venting and energy usage for equipment. Improvements on the energy efficiency of equipment would reduce emissions further but this could be challenging. Improvement of injection capacity and elimination of venting/flaring or fugitive gas are methods more likely to be utilized for reducing net emissions and are the cases used for the optimized scenario in this work. This LCA illustrated the potential for the CO₂-EOR operations in the FWU to store more CO₂ with minimal emissions. Full article

(This article belongs to the Special Issue Forecasting CO₂ Sequestration with Enhanced Oil Recovery)

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14 pages, 3534 KiB

Open AccessArticle

Relative Permeability: A Critical Parameter in Numerical Simulations of Multiphase Flow in Porous Media

by Nathan Moodie, William Ampomah, Wei Jia and Brian McPherson

Energies 2021, 14(9), 2370; https://doi.org/10.3390/en14092370 - 22 Apr 2021

Cited by 5 | Viewed by 2125

Abstract

Effective multiphase flow and transport simulations are a critical tool for screening, selection, and operation of geological CO₂ storage sites. The relative permeability curve assumed for these simulations can introduce a large source of uncertainty. It significantly impacts forecasts of all aspects of the reservoir simulation, from CO₂ trapping efficiency and phase behavior to volumes of oil, water, and gas produced. Careful consideration must be given to this relationship, so a primary goal of this study is to evaluate the impacts on CO₂-EOR model forecasts of a wide range of relevant relative permeability curves, from near linear to highly curved. The Farnsworth Unit (FWU) is an active CO₂-EOR operation in the Texas Panhandle and the location of our study site. The Morrow ‘B’ Sandstone, a clastic formation composed of medium to coarse sands, is the target storage formation. Results indicate that uncertainty in the relative permeability curve can impart a significant impact on model predictions. Therefore, selecting an appropriate relative permeability curve for the reservoir of interest is critical for CO₂-EOR model design. If measured laboratory relative permeability data are not available, it must be considered as a significant source of uncertainty. Full article

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18 pages, 3572 KiB

Open AccessArticle

Risk Assessment and Management Workflow—An Example of the Southwest Regional Partnership

by Si-Yong Lee, Ken Hnottavange-Telleen, Wei Jia, Ting Xiao, Hari Viswanathan, Shaoping Chu, Zhenxue Dai, Feng Pan, Brian McPherson and Robert Balch

Energies 2021, 14(7), 1908; https://doi.org/10.3390/en14071908 - 30 Mar 2021

Cited by 6 | Viewed by 2601

Abstract

This paper summarizes the risk assessment and management workflow developed and applied to the Southwest Regional Partnership on Carbon Sequestration (SWP) Phase III Demonstration Project. The risk assessment and management workflow consists of six primary tasks, including management planning, identification, qualitative analysis, quantitative analysis, response planning, and monitoring. Within the workflow, the SWP assembled and iteratively updated a risk registry that identifies risks for all major activities of the project. Risk elements were ranked with respect to the potential impact to the project and the likelihood of occurrence. Both qualitative and quantitative risk analyses were performed. To graphically depict the interactions among risk elements and help building risk scenarios, process influence diagrams were used to represent the interactions. The SWP employed quantitative methods of risk analysis including Response Surface Method (RSM), Polynomial Chaos Expansion (PCE), and the National Risk Assessment Partnership (NRAP) toolset. The SWP also developed risk response planning and performed risk control and monitoring to prevent the risks from affecting the project and ensure the effectiveness of risk management. As part of risk control and monitoring, existing and new risks have been tracked and the response plan was subsequently evaluated. Findings and lessons learned from the SWP’s risk assessment and management efforts will provide valuable information for other commercial geological CO₂ storage projects. Full article

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22 pages, 7003 KiB

Open AccessArticle

Impact of Mineral Reactive Surface Area on Forecasting Geological Carbon Sequestration in a CO₂-EOR Field

by Wei Jia, Ting Xiao, Zhidi Wu, Zhenxue Dai and Brian McPherson

Energies 2021, 14(6), 1608; https://doi.org/10.3390/en14061608 - 14 Mar 2021

Cited by 17 | Viewed by 2271

Abstract

Mineral reactive surface area (RSA) is one of the key factors that control mineral reactions, as it describes how much mineral is accessible and can participate in reactions. This work aims to evaluate the impact of mineral RSA on numerical simulations for CO₂ storage at depleted oil fields. The Farnsworth Unit (FWU) in northern Texas was chosen as a case study. A simplified model was used to screen representative cases from 87 RSA combinations to reduce the computational cost. Three selected cases with low, mid, and high RSA values were used for the FWU model. Results suggest that the impact of RSA values on CO₂ mineral trapping is more complex than it is on individual reactions. While the low RSA case predicted negligible porosity change and an insignificant amount of CO₂ mineral trapping for the FWU model, the mid and high RSA cases forecasted up to 1.19% and 5.04% of porosity reduction due to mineral reactions, and 2.46% and 9.44% of total CO₂ trapped in minerals by the end of the 600-year simulation, respectively. The presence of hydrocarbons affects geochemical reactions and can lead to net CO₂ mineral trapping, whereas mineral dissolution is forecasted when hydrocarbons are removed from the system. Full article

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26 pages, 8132 KiB

Open AccessArticle

Practical CO₂—WAG Field Operational Designs Using Hybrid Numerical-Machine-Learning Approaches

by Qian Sun, William Ampomah, Junyu You, Martha Cather and Robert Balch

Energies 2021, 14(4), 1055; https://doi.org/10.3390/en14041055 - 17 Feb 2021

Cited by 8 | Viewed by 2320

Abstract

Machine-learning technologies have exhibited robust competences in solving many petroleum engineering problems. The accurate predictivity and fast computational speed enable a large volume of time-consuming engineering processes such as history-matching and field development optimization. The Southwest Regional Partnership on Carbon Sequestration (SWP) project desires rigorous history-matching and multi-objective optimization processes, which fits the superiorities of the machine-learning approaches. Although the machine-learning proxy models are trained and validated before imposing to solve practical problems, the error margin would essentially introduce uncertainties to the results. In this paper, a hybrid numerical machine-learning workflow solving various optimization problems is presented. By coupling the expert machine-learning proxies with a global optimizer, the workflow successfully solves the history-matching and CO₂ water alternative gas (WAG) design problem with low computational overheads. The history-matching work considers the heterogeneities of multiphase relative characteristics, and the CO₂-WAG injection design takes multiple techno-economic objective functions into accounts. This work trained an expert response surface, a support vector machine, and a multi-layer neural network as proxy models to effectively learn the high-dimensional nonlinear data structure. The proposed workflow suggests revisiting the high-fidelity numerical simulator for validation purposes. The experience gained from this work would provide valuable guiding insights to similar CO₂ enhanced oil recovery (EOR) projects. Full article

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14 pages, 6390 KiB

Open AccessArticle

Chemical Impacts of Potential CO₂ and Brine Leakage on Groundwater Quality with Quantitative Risk Assessment: A Case Study of the Farnsworth Unit

by Ting Xiao, Brian McPherson, Richard Esser, Wei Jia, Zhenxue Dai, Shaoping Chu, Feng Pan and Hari Viswanathan

Energies 2020, 13(24), 6574; https://doi.org/10.3390/en13246574 - 14 Dec 2020

Cited by 14 | Viewed by 2271

Abstract

Potential leakage of reservoir fluids is considered a key risk factor for geologic CO₂ sequestration (GCS), with concerns of their chemical impacts on the quality of overlying underground sources of drinking water (USDWs). Effective risk assessment provides useful information to guide GCS activities for protecting USDWs. In this study, we present a quantified risk assessment case study of an active commercial-scale CO₂-enhanced oil recovery (CO₂-EOR) and sequestration field, the Farnsworth Unit (FWU). Specific objectives of this study include: (1) to quantify potential risks of CO₂ and brine leakage to the overlying USDW quality with response surface methodology (RSM); and (2) to identify water chemistry indicators for early detection criteria. Results suggest that trace metals (e.g., arsenic and selenium) are less likely to become a risk due to their adsorption onto clay minerals; no-impact thresholds based on site monitoring data could be a preferable reference for early groundwater quality evaluation; and pH is suggested as an indicator for early detection of a leakage. This study may provide quantitative insight for monitoring strategies on GCS sites to enhance the safety of long-term CO₂ sequestration. Full article

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26 pages, 5348 KiB

Open AccessProject Report

Deposition, Diagenesis, and Sequence Stratigraphy of the Pennsylvanian Morrowan and Atokan Intervals at Farnsworth Unit

by Martha Cather, Dylan Rose-Coss, Sara Gallagher, Natasha Trujillo, Steven Cather, Robert Spencer Hollingworth, Peter Mozley and Ryan J. Leary

Energies 2021, 14(4), 1057; https://doi.org/10.3390/en14041057 - 17 Feb 2021

Cited by 19 | Viewed by 2454

Abstract

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. Full article

(This article belongs to the Special Issue Forecasting CO₂ Sequestration with Enhanced Oil Recovery)

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