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All sourcesNASA NTRSDOE OSTI
NASA NTRS2024

Depositional History of the Upper Sequence of the Western Fan: Evidence for Late-Stage Fluvial and Potential Igneous Activity, Jezero Crater, Mars

Within Jezero crater, a 45 km diameter Noachian-aged crater on Mars, the Upper Fan group (UFg) stratigraphy records the youngest interval of sediment deposition via aqueous activity on the western fan. From orbital images, the UFg surface is characterized by ridges interpreted to be associated with channels that can be group based on orientation into distinct elongate and fan-shaped deposits. UFg deposits primarily consist of a sandstone to granule conglomerate facies covered by a lithified boulder conglomerate or dense accumulations of loose boulders along the surface. The coarse-grained nature of UFg deposits and the unconformable contact with the underlying fan stratigraphy suggest that the UFg represents a higher-energy shift from the relatively longer-lived, lower-energy aqueous systems interpreted in underlying fan stratigraphy. The Mars 2020 Perseverance rover encountered the main exposures of the UFg deposits beginning on Sol 755 and has been continuously collecting data along its northwestward traverse across the fan, enabling reconciliation of orbitally-derived geomorphology with in-situ observations from the rover and Ingenuity helicopter. This work represents a combined assessment of the geomorphology and the sedimentology and stratigraphy of the UFg in order to establish its depositional and emplacement history. Determining the origins of the Upper Fan sequence will clarify how, when, and in what order aqueous environments evolved through time within Jezero crater (e.g. crater infill, overflow, breach, and lake level drop;). Finally, this work will provide critical context for the three rock samples within the UFg sample suite.

Mars 2020↗
NASA NTRS2026

Diverse organic molecules on Mars revealed by the first SAM TMAH experiment

The search for organic matter on Mars has rapidly evolved in the past decade with simple aromatic, S-heterocycles, and aliphatic organic molecules detected in Gale crater. We report the in situ detection of >20 organic molecules from clay-bearing sandstones in the ~3.5-billion-year-old Knockfarrill Hill member of Glen Torridon, Gale crater, by the Sample Analysis at Mars instrument suite onboard the Curiosity rover. These molecules were liberated by the onboard tetramethylammonium hydroxide wet chemistry experiment. Diverse thermochemolysis products, including benzothiophene, methyl benzoate, and single and dicyclic aromatic molecules were released and detected by evolved gas analysis and gas chromatography-mass spectrometry. Results indicate the experiment successfully released molecules preserved in ancient macromolecular or free organic matter within Martian bedrock despite ~3.5 billion years of diagenesis and radiation exposure.

Amy J Williams↗
DOE OSTI2011

Simulation of CO2 Sequestration at Rock Spring Uplift, Wyoming: Heterogeneity and Uncertainties in Storage Capacity, Injectivity and Leakage

Many geological, geochemical, geomechanical and hydrogeological factors control CO{sub 2} storage in subsurface. Among them heterogeneity in saline aquifer can seriously influence design of injection wells, CO{sub 2} injection rate, CO{sub 2} plume migration, storage capacity, and potential leakage and risk assessment. This study applies indicator geostatistics, transition probability and Markov chain model at the Rock Springs Uplift, Wyoming generating facies-based heterogeneous fields for porosity and permeability in target saline aquifer (Pennsylvanian Weber sandstone) and surrounding rocks (Phosphoria, Madison and cap-rock Chugwater). A multiphase flow simulator FEHM is then used to model injection of CO{sub 2} into the target saline aquifer involving field-scale heterogeneity. The results reveal that (1) CO{sub 2} injection rates in different injection wells significantly change with local permeability distributions; (2) brine production rates in different pumping wells are also significantly impacted by the spatial heterogeneity in permeability; (3) liquid pressure evolution during and after CO{sub 2} injection in saline aquifer varies greatly for different realizations of random permeability fields, and this has potential important effects on hydraulic fracturing of the reservoir rock, reactivation of pre-existing faults and the integrity of the cap-rock; (4) CO{sub 2} storage capacity estimate for Rock Springs Uplift is 6614 {+-} 256 Mt at 95% confidence interval, which is about 36% of previous estimate based on homogeneous and isotropic storage formation; (5) density profiles show that the density of injected CO{sub 2} below 3 km is close to that of the ambient brine with given geothermal gradient and brine concentration, which indicates CO{sub 2} plume can sink to the deep before reaching thermal equilibrium with brine. Finally, we present uncertainty analysis of CO{sub 2} leakage into overlying formations due to heterogeneity in both the target saline aquifer and surrounding formations. This uncertainty in leakage will be used to feed into risk assessment modeling.

BRINES↗
DOE OSTI2011

Application of real rock pore-threat statistics to a regular pore network model

This work reports the application of real rock statistical data to a previously developed regular pore network model in an attempt to produce an accurate simulation tool with low computational overhead. A core plug from the St. Peter Sandstone formation in Indiana was scanned with a high resolution micro CT scanner. The pore-throat statistics of the three-dimensional reconstructed rock were extracted and the distribution of the pore-throat sizes was applied to the regular pore network model. In order to keep the equivalent model regular, only the throat area or the throat radius was varied. Ten realizations of randomly distributed throat sizes were generated to simulate the drainage process and relative permeability was calculated and compared with the experimentally determined values of the original rock sample. The numerical and experimental procedures are explained in detail and the performance of the model in relation to the experimental data is discussed and analyzed. Petrophysical properties such as relative permeability are important in many applied fields such as production of petroleum fluids, enhanced oil recovery, carbon dioxide sequestration, ground water flow, etc. Relative permeability data are used for a wide range of conventional reservoir engineering calculations and in numerical reservoir simulation. Two-phase oil water relative permeability data are generated on the same core plug from both pore network model and experimental procedure. The shape and size of the relative permeability curves were compared and analyzed and good match has been observed for wetting phase relative permeability but for non-wetting phase, simulation results were found to be deviated from the experimental ones. Efforts to determine petrophysical properties of rocks using numerical techniques are to eliminate the necessity of regular core analysis, which can be time consuming and expensive. So a numerical technique is expected to be fast and to produce reliable results. In applied engineering, sometimes quick result with reasonable accuracy is acceptable than the more time consuming results. Present work is an effort to check the accuracy and validity of a previously developed pore network model for obtaining important petrophysical properties of rocks based on cutting-sized sample data.

58 GEOSCIENCES↗
DOE OSTI2011

Application of real rock pore-throat statistics to a regular pore network model

This work reports the application of real rock statistical data to a previously developed regular pore network model in an attempt to produce an accurate simulation tool with low computational overhead. A core plug from the St. Peter Sandstone formation in Indiana was scanned with a high resolution micro CT scanner. The pore-throat statistics of the three-dimensional reconstructed rock were extracted and the distribution of the pore-throat sizes was applied to the regular pore network model. In order to keep the equivalent model regular, only the throat area or the throat radius was varied. Ten realizations of randomly distributed throat sizes were generated to simulate the drainage process and relative permeability was calculated and compared with the experimentally determined values of the original rock sample. The numerical and experimental procedures are explained in detail and the performance of the model in relation to the experimental data is discussed and analyzed. Petrophysical properties such as relative permeability are important in many applied fields such as production of petroleum fluids, enhanced oil recovery, carbon dioxide sequestration, ground water flow, etc. Relative permeability data are used for a wide range of conventional reservoir engineering calculations and in numerical reservoir simulation. Two-phase oil water relative permeability data are generated on the same core plug from both pore network model and experimental procedure. The shape and size of the relative permeability curves were compared and analyzed and good match has been observed for wetting phase relative permeability but for non-wetting phase, simulation results were found to be deviated from the experimental ones. Efforts to determine petrophysical properties of rocks using numerical techniques are to eliminate the necessity of regular core analysis, which can be time consuming and expensive. So a numerical technique is expected to be fast and to produce reliable results. In applied engineering, sometimes quick result with reasonable accuracy is acceptable than the more time consuming results. Present work is an effort to check the accuracy and validity of a previously developed pore network model for obtaining important petrophysical properties of rocks based on cutting-sized sample data. Introduction

42 ENGINEERING↗
DOE OSTI2011

Variable Density Flow Modeling for Simulation Framework for Regional Geologic CO{sub 2} Storage Along Arches Province of Midwestern United States

The Arches Province in the Midwestern U.S. has been identified as a major area for carbon dioxide (CO{sub 2}) storage applications because of the intersection of Mt. Simon sandstone reservoir thickness and permeability. To better understand large-scale CO{sub 2} storage infrastructure requirements in the Arches Province, variable density scoping level modeling was completed. Three main tasks were completed for the variable density modeling: Single-phase, variable density groundwater flow modeling; Scoping level multi-phase simulations; and Preliminary basin-scale multi-phase simulations. The variable density modeling task was successful in evaluating appropriate input data for the Arches Province numerical simulations. Data from the geocellular model developed earlier in the project were translated into preliminary numerical models. These models were calibrated to observed conditions in the Mt. Simon, suggesting a suitable geologic depiction of the system. The initial models were used to assess boundary conditions, calibrate to reservoir conditions, examine grid dimensions, evaluate upscaling items, and develop regional storage field scenarios. The task also provided practical information on items related to CO{sub 2} storage applications in the Arches Province such as pressure buildup estimates, well spacing limitations, and injection field arrangements. The Arches Simulation project is a three-year effort and part of the United States Department of Energy (U.S. DOE)/National Energy Technology Laboratory (NETL) program on innovative and advanced technologies and protocols for monitoring/verification/accounting (MVA), simulation, and risk assessment of CO{sub 2} sequestration in geologic formations. The overall objective of the project is to develop a simulation framework for regional geologic CO{sub 2} storage infrastructure along the Arches Province of the Midwestern U.S.

54 ENVIRONMENTAL SCIENCES↗
DOE OSTI2013

EGS rock reactions with Supercritical CO2 saturated with water and water saturated with Supercritical CO2

EGS using CO2 as a working fluid will likely involve hydro-shearing low-permeability hot rock reservoirs with a water solution. After that process, the fractures will be flushed with CO2 that is maintained under supercritical conditions (> 70 bars). Much of the injected water in the main fracture will be flushed out with the initial CO2 injection; however side fractures, micro fractures, and the lower portion of the fracture will contain connate water that will interact with the rock and the injected CO2. Dissolution/precipitation reactions in the resulting scCO2/brine/rock systems have the potential to significantly alter reservoir permeability, so it is important to understand where these precipitates form and how are they related to the evolving ‘free’ connate water in the system. To examine dissolution / precipitation behavior in such systems over time, we have conducted non-stirred batch experiments in the laboratory with pure minerals, sandstone, and basalt coupons with brine solution spiked with MnCl2 and scCO2. The coupons are exposed to liquid water saturated with scCO2 and extend above the water surface allowing the upper portion of the coupons to be exposed to scCO2 saturated with water. The coupons were subsequently analyzed using SEM to determine the location of reactions in both in and out of the liquid water. Results of these will be summarized with regard to significance for EGS with CO2 as a working fluid.

15 GEOTHERMAL ENERGY↗
DOE OSTI2014

The Potosi Reservoir Model 2014

As a part of a larger project co-funded by the United States Department of Energy (US DOE) to evaluate the potential of formations within the Cambro-Ordovician strata above the Mt. Simon Sandstone as potential targets for carbon sequestration in the Illinois and Michigan Basins, the Illinois State Geological Survey (ISGS) requested Schlumberger to evaluate the potential injectivity and carbon dioxide (CO2) plume size of the Cambrian Potosi Formation. The evaluation of this formation was accomplished using wireline data, core data, pressure data, and seismic data from this project as well as two other separately funded projects: the United States Department of Energy-funded Illinois Basin – Decatur Project (IBDP) being conducted by the Midwest Geological Sequestration Consortium (MGSC) in Macon County, Illinois, and the Illinois Industrial Carbon Capture and Sequestration (IL-ICCS) project funded through the American Recovery and Reinvestment Act.

Smith, Valerie↗
DOE OSTI2014

Risk Evaluation for CO2 Geosequestration in the Knox Supergroup, Illinois Basin Final Report

This report describes a process and provides seed information for identifying and evaluating risks pertinent to a hypothetical carbon dioxide (CO2) capture and sequestration (CCS) project. In the envisioned project, the target sequestration reservoir rock is the Potosi Formation of the Knox Supergroup. The Potosi is identified as a potential target formation because (1) at least locally, it contains vuggy to cavernous layers that have very high porosity, and (2) it is present in areas where the deeper Mt. Simon Sandstone (a known potential reservoir unit) is absent or nonporous. The key report content is discussed in Section 3.3, which describes two lists of Features, Events, and Processes (FEPs) that should be considered during the design stage of such a project. These lists primarily highlight risk elements particular to the establishment of the Potosi as the target formation in general. The lists are consciously incomplete with respect to risk elements that would be relevant for essentially all CCS projects regardless of location or geology. In addition, other risk elements specific to a particular future project site would have to be identified. Sources for the FEPs and scenarios listed here include the iconic Quintessa FEPs list developed for the International Energy Agency Greenhouse Gas (IEAGHG) Programme; previous risk evaluation projects executed by Schlumberger Carbon Services; and new input solicited from experts currently working on aspects of CCS in the Knox geology. The projects used as sources of risk information are primarily those that have targeted carbonate reservoir rocks similar in age, stratigraphy, and mineralogy to the Knox-Potosi. Risks of using the Potosi Formation as the target sequestration reservoir for a CCS project include uncertainties about the levels of porosity and permeability of that rock unit; the lateral consistency and continuity of those properties; and the ability of the project team to identify suitable (i.e., persistently porous and permeable) injection depths within the overall formation. Less direct implications include the vertical position of the Potosi within the rock column and the absence of a laterally extensive shale caprock immediately overlying the Potosi. Based on modeling work done partly in association with this risk report, risks that should also be evaluated include the ability of available methods to predict and track the development of a CO2 plume as it migrates away from the injection point(s). The geologic and hydrodynamic uncertainties present risks that are compounded at the stage of acquiring necessary drilling and injection permits. It is anticipated that, in the future, a regional geologic study or CO2-emitter request may identify a small specific area as a prospective CCS project site. At that point, the FEPs lists provided in this report should be evaluated by experts for their relative levels of risk. A procedure for this evaluation is provided. The higher-risk FEPs should then be used to write project-specific scenarios that may themselves be evaluated for risk. Then, actions to reduce and to manage risk can be described and undertaken. The FEPs lists provided as Appendix 2 should not be considered complete, as potentially the most important risks are ones that have not yet been thought of. But these lists are intended to include the most important risk elements pertinent to a Potosi-target CCS project, and they provide a good starting point for diligent risk identification, evaluation, and management.

Hnottavange-Telleen, Ken↗
DOE OSTI2015

Relative permeability of hydrate-bearing sediments from percolation theory and critical path analysis: theoretical and experimental results

Relative permeabilities to water and gas are important parameters for accurate modeling of the formation of methane hydrate deposits and production of methane from hydrate reservoirs. Experimental measurements of gas and water permeability in the presence of hydrate are difficult to obtain. The few datasets that do exist suggest that relative permeability obeys a power law relationship with water or gas saturation with exponents ranging from around 2 to greater than 10. Critical path analysis and percolation theory provide a framework for interpreting the saturation-dependence of relative permeability based on percolation thresholds and the breadth of pore size distributions, which may be determined easily from 3-D images or gas adsorption-desorption hysteresis. We show that the exponent of the permeability-saturation relationship for relative permeability to water is related to the breadth of the pore size distribution, with broader pore size distributions corresponding to larger exponents. Relative permeability to water in well-sorted sediments with narrow pore size distributions, such as Berea sandstone or Toyoura sand, follows percolation scaling with an exponent of 2. On the other hand, pore-size distributions determined from argon adsorption measurements we performed on clays from the Nankai Trough suggest that relative permeability to water in fine-grained intervals may be characterized by exponents as large as 10 as determined from critical path analysis. We also show that relative permeability to the gas phase follows percolation scaling with a quadratic dependence on gas saturation, but the threshold gas saturation for percolation changes with hydrate saturation, which is an important consideration in systems in which both hydrate and gas are present, such as during production from a hydrate reservoir. Our work shows how measurements of pore size distributions from 3-D imaging or gas adsorption may be used to determine relative permeabilities.

Daigle, Hugh↗
DOE OSTI2015

Drilling, Completion, and Data Collection Plans An Assessment of Geological Carbon Sequestration Options in the Illinois Basin: Phase III

Executive Summary The Illinois Basin – Decatur Project (IBDP) is managed by the Midwest Geological Sequestration Consortium (MGSC) and is led by the Illinois State Geological Survey (ISGS) at the University of Illinois. The project site is located on the Archer Daniels Midland Company (ADM) property in Decatur, Illinois, and is a fully integrated carbon capture and storage (CCS) project that uses CO₂ captured from the ethanol-producing fermentation process at the ADM corn-processing plant (Finley et. al., 2013). IBDP has a goal of injecting one million tonnes of CO₂ into the basal sands of the Mt. Simon Sandstone over a three-year period. This is a multifaceted project, and this report details the planning and results of the drilling, completions, well testing, log data acquisition, and the Health, Safety, and Environment (HSE) aspects of the project. Three deep wells were planned for the IBDP: • The injection well: Injection Well #1 (CCS1); • The monitoring well (both in-zone and above seal): Verification Well #1 (VW1); and • The geophone monitoring well: Geophysical Monitoring Well #1 (GM1). The detailed plans for these wells are attached to the appendices of this document. The wells were drilled successfully with little deviation from the original plans. The biggest change from the plan to execution was the need to adjust for larger-than-expected loss of circulation in the Potosi section of the Knox Formation. The completions reports also attached to this document detail the well constructions as they were actually built. Injectivity testing was carried out, and the perforating plans were adjusted based on the results. Additional perforations and acidizing were performed as a result of the injectivity testing. The testing plans are detailed in this report along with the actual testing results. The injectivity testing results were used in the modeling and simulation efforts. Detailed HSE plans were developed and implemented during the planning and execution phases of the project. The implementation included an HSE Bridging Document, which served to unify the HSE policies of the project partners and key subcontractors. The HSE plan and actual HSE results are presented in this document. There were no recordable HSE incidents during the project. A detailed logging program was developed based on project needs. The log data were acquired in accordance with the plan, and both the plan and log results are presented in this report. Log data were heavily utilized by the research staff, modelers, reservoir engineers, and for technical and permitting efforts. 5 Several key lessons were learned during the project: • Safety in operations and execution is paramount and is only achieved through proper planning and behavior control. The certainty of this was reinforced through implementation of this lesson and the resultant flawless HSE performance during the project. • Losses of drilling fluid circulation were larger than anticipated within the Potosi Formation. Circulation was only recovered through cementing the loss zones. • When possible, minimizing complexity in permit requirements and well designs is preferable. • The size of the wells were outside of the standard experience and expertise typical within the basin, and therefore required substantial planning and ramp-up of contractors and partners to meet project objectives. • With multiple stakeholders and research partners, establishing objectives and requirements early and adhering to change request procedures throughout the project are critical to manage competing data and sampling objectives that may be detrimental to overall progress. The well construction and completion operations were successfully executed, with all wells built in a manner that achieved excellent wellbore integrity. Log planning involved a number of stakeholders and technical specialists. Data collection from logging, coring, and testing was excellent. Time and effort spent with the associated contractors and suppliers to develop a well plan beyond normal scope proved highly successful, resulting in a well-construction and completion project that surpassed expectations. The world-class HSE results also demonstrate the commitment of all stakeholders in the project. The details follow in the body of this document

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2012

MODELING OF FLOW AND TRANSPORT INDUCED BY PRODUCTION OF HYDROFRACTURE-STIMULATED GAS WELLS NEAR THE RULISON NUCLEAR TEST

The Piceance Basin in western Colorado contains significant reserves of natural gas in poorly connected, low-permeability (tight) sandstone lenses of the Mesaverde Group. The ability to enhance the production of natural gas in this area has long been a goal of the oil and gas industry. The U.S. Atomic Energy Commission, a predecessor agency to the U.S. Department of Energy (DOE) and the U.S. Nuclear Regulatory Commission, participated in three tests using nuclear detonations to fracture tight formations in an effort to enhance gas production. The tests were conducted under Project Plowshare, a program designed to identify peaceful, beneficial uses for nuclear devices. The first, Project Gasbuggy, was conducted in 1967 in the San Juan Basin of New Mexico. The two subsequent tests, Project Rulison in 1969 and Project Rio Blanco in 1973, were in the Piceance Basin. The ability to enhance natural gas production from tight sands has become practical through advances in hydraulic fracturing technology (hydrofracturing). This technology has led to an increase in drilling activity near the Rulison site, raising concerns that contamination currently contained in the subsurface could be released through a gas well drilled too close to the site. As wells are drilled nearer the site, the DOE Office of Legacy Management has taken the approach outlined in the June 2010 Rulison Path Forward document (DOE 2010), which recommends a conservative, staged approach to gas development. Drillers are encouraged to drill wells in areas with a low likelihood of encountering contamination (both distance and direction from the detonation zone are factors) and to collect data from these wells prior to drilling nearer the site’s 40 acre institutional control boundary (Lot 11). Previous modeling results indicate that contamination has been contained within Lot 11 (Figure 1). The Path Forward document couples the model predictions with the monitoring of gas and produced water from the gas wells and the monitoring of shallow groundwater near the site.

tritium, nuclear fracturing, hydraulic fracturing,↗
DOE OSTI2016

The impact of flow focusing on gas hydrate accumulations in overpressured marine sediments

This study demonstrates the potential for flow focusing due to overpressuring in marine sedimentary environments to act as a significant methane transport mechanism from which methane hydrate can precipitate in large quantities in dipping sandstone bodies. Traditionally, gas hydrate accumulations in nature are discussed as resulting from either short-range diffusive methane migration or from long-range advective fluid transport sourced from depth. However, 3D simulations performed in this study demonstrate that a third migration mechanism, short-range advective transport, can provide a significant methane source that is unencumbered by limitations of the other two end-member mechanisms. Short-range advective sourcing is advantageous over diffusion because it can convey greater amounts of methane to sands over shorter timespans, yet it is not necessarily limited by down-dip pore blocking in sands as is typical of updip advection from a deep source. These results are novel because they integrate pore size impacts on spatial solubility gradients, grid block properties that evolve through time, and methane sourcing through microbial methanogenesis into a holistic characterization of environments exposed to multiple methane hydrate sourcing mechanisms. We show that flow focusing toward sand bodies transports large quantities of methane, the magnitude of which are determined by the sand-clay solubility contrast, and generates larger quantities of hydrate in sands than a solely diffusive system; after depositing methane as hydrate, fluid exiting a sand body is depleted in methane and leaves a hydrate free region in its wake above the sand. Additionally, we demonstrate that in overpressured environments, hydrate growth is initially diffusively dominated before transitioning to an advection-dominated regime. The timescale and depth at which this transition takes place depends primarily on the rate of microbial metabolism and the sedimentation rate but only depends loosely on the degree of overpressuring.

Nole, Michael↗
DOE OSTI2017

Optimization of Well Configuration for a Sedimentary Enhanced Geothermal Reservoir

The extraction of geothermal energy in the form of hot water from sedimentary rock formations could expand the current geothermal energy resources toward new regions. From previous work, we observed that sedimentary geothermal reservoirs with relatively low permeability would require the application of enhancement techniques (e.g., well hydraulic stimulation) to achieve commercial production/injection rates. In this paper we extend our previous work to develop a methodology to determine the optimum well configuration that maximizes the hydraulic performance of the geothermal system. The geothermal systems considered consist of one vertical well doublet system with hydraulic fractures, and three horizontal well configurations with open-hole completion, longitudinal fractures and transverse fractures, respectively. A commercial thermal reservoir simulation is used to evaluate the geothermal reservoir performance using as design parameters the well spacing and the length of the horizontal wells. The results obtained from the numerical simulations are used to build a response surface model based on the multiple linear regression method. The optimum configuration of the sedimentary geothermal systems is obtained from the analysis of the response surface model. The proposed methodology is applied to a case study based on a reservoir model of the Lyons sandstone formation, located in the Wattenberg field, Denver-Julesburg basin, Colorado.

15 GEOTHERMAL ENERGY↗
DOE OSTI2017

The U.S. Gas Flooding Experience: CO2 Injection Strategies and Impact on Ultimate Recovery

The Permian Basin in West Texas and southwestern New Mexico has seen 45 years of oil reserve growth through CO2 enhanced oil recovery (CO2 EOR). More than 60 CO2 EOR projects are currently active in the region’s limestone, sandstone and dolomite reservoirs. Water alternating gas (WAG) has been the development strategy of choice in the Permian for several technical and economic reasons. More recently, the technology started to get implemented in the much more porous and permeable clastic depositional systems of the onshore U.S. Gulf Coast. Continued CO2 injection (CGI), as opposed to WAG, was selected as the injection strategy to develop Gulf Coast oil fields, where CO2 injection volumes are significantly larger (up to 6 times larger) than those of the Permian. We conducted a compositional simulation based study with the objective of comparing the CO2 utilization ratios (volume of CO2 injected to produce a barrel of oil) of 4 conventional and novel CO2 injection strategies: (1) continuous gas injection (CGI), (2) water alternating gas (WAG), (3) water curtain injection (WCI), and (4) WAG and WCI combination. These injection scenarios were simulated using the GEM module from the Computer Modeling Group (CMG). GEM is an advanced general equation-of-state compositional simulator, which includes equation of state, CO2 miscible flood, CO2/brine interactions, and complex phase behavior. The simulator is set up to model three fluid phases including water, oil, and gas. Our study demonstrates how the selected field development strategy has a significant impact on the ultimate recovery of CO2-EOR projects, with GCI injection providing maximum oil recovery in absolute volume terms, but with WAG offering a more balanced technical-economical approach.

02 PETROLEUM↗
DOE OSTI2018

Data Gap Assessment Subtask 4.1 Topical Report

Data sets were compiled and assessed for the Cambro-Ordovician Storage Complex across the CarbonSAFE Illinois East Sub-Basin study area to assess the data needs to support drilling a stratigraphic borehole at the East Sub-Basin case study site located at the Wabash Integrated Gasification Combined Cycle (IGCC) plant north of Terre Haute, Indiana. Available data for the Mt. Simon Sandstone, within a 50 mile range in the East Sub-Basin study area, was assembled and cataloged. A summary of regional data documenting seal penetrations in the Cambrian Eau Claire and Ordovician Maquoketa was compiled, but a lack of deep well control over the project area illustrates the need for test boring and data acquisition at the East Sub-Basin case study site.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2018

An Assessment of the National Risk Assessment Program’s CO 2 Sequestration Leakage Modeling Tools, Subtask 6.1 – NRAP Assessment Topical Report

The CarbonSAFE East Sub-Basin project team explored and assessed the carbon sequestration site characterization National Risk Assessment Partnership (NRAP) Toolset, developed by the National Energy Technology Laboratory, Lawrence Berkeley National Laboratory, Lawrence Livermore National Laboratory, Los Alamos National Laboratory, and Pacific Northwest National Laboratory (PNNL) for the NRAP. We ran the Integrated Assessment Model (IAM) tool using inputs derived from verified regional geologic data. We investigated CO 2 and brine leakage rates, and total CO 2 and brine leaked, from a hypothetical cemented injection well borehole to the nearest underground source of drinking water (USDW), identified as the St. Peter Sandstone, in a hypothetical monitoring well. The distance of the monitoring well from the injection well was varied to identify leakage variations with increasing distance from the injection well and to establish an area of review (AOR) for the project, and the effect of high and low wellbore cement permeability on model results was compared.

01 COAL, LIGNITE, AND PEAT↗