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All sourcesNASA NTRSDOE OSTI
DOE OSTI2024

HERO CarbonSAFE Phase 2 Project in the Columbia River Basalt Group

The Hermiston, Oregon Basalt CarbonSAFE Phase II project (HERO CarbonSAFE) seeks to accelerate the deployment of commercial carbon dioxide (CO2) storage projects in basaltic rocks. Basalt CO2 storage has several advantages to conventional saline storage reservoirs including 1. The potential for rapid mineralization of CO2, 2. Associated decreases in pressure and CO2 migration risks, 3. Reduced long-term monitoring requirements with respect to plume tracking, 4. Widespread geographic distribution and, 5. Large storage potential due to thickness, porosity, and CO2 interactions with basalt. And for locations such as the Pacific Northwest, Hawaii, Iceland, India and Japan, basalts may offer the only economically feasible option for local CO2 storage. However, there are limited field-scale assessments of CO2 storage in basalt, and current carbon capture utilization and storage (CCUS) permitting and regulatory frameworks were developed for conventional saline reservoirs. HERO CarbonSAFE is designed to address research gaps and uncertainties associated with basalt storage. Specifically, the project will assess the feasibility of CO2 injection in the deep layered basalts, long-term storage (mineralization), practical approaches for large-scale implementation (50+ million metric tons of CO2 over 30 years), lithology-specific risks, and the technoeconomic potential for CO2 storage in basalts. The HERO CarbonSAFE project will assess feasibility of developing a commercial-scale (50+ million metric tons of CO2) geological storage complex within the Columbia River Basalt Group (CRBG), a layered continental flood basalt complex that underlies Calpine’s natural gas-fired Hermiston Power Project (HPP) in Hermiston, OR (Figure 1). Under this 2-year CarbonSAFE Phase II project, the HERO team will conduct a data acquisition campaign that includes drilling a stratigraphic well to a total depth of ~1,500 m into the thick layered basalts proximal to HPP. A comprehensive well logging and hydrologic testing program will be augmented with new core collected from flow zones and sealing units, and comprehensive laboratory testing to help refine the kinetic rates of mineralization. The newly acquired information will be integrated with existing data from regional wells to correlate basalt injection zone properties to develop storage hub/commercial-scale models. Using these models, the project team will evaluate injection scenarios to define the technical and economic potential for storing a minimum of 50 million metric tons of CO2 over a 30-year period, along with a robust sensitivity analysis on key parameters governing reservoir viability for sustainable injection over a commercial project lifetime. Specific technical objectives of HERO are: (1) assessing the reservoir response of a series of stacked layered reservoir flowtop sequences occurring in this area of the CRBG to commercial-scale injection volumes; (2) extending prior efforts by the project team to characterize the deep layered basalts encountered in regional studies, to leverage prior investments by U.S. Department of Energy’s (DOE) Carbon Storage program; (3) leveraging DOE’s mineralization characterization efforts to advance model parametrization for commercial scale injection of CO2 in basalts; (4) conducting risk assessments associated with scaling up to commercial storage hub injection goals, while validating DOE’s National Risk Assessment Partnership (NRAP) tools, to identify potential constraints that would prevent the CRBG from serving as a commercial-scale storage complex; (5) developing mitigation plans to address identified risks; (6) developing a commercial-scale injection and monitoring, verification and accounting (MVA) strategy; (7) utilizing computational models to define and minimize, if possible, the Area of Review (AoR) under Class VI regulations; and (8) developing a robust CO2 management strategy for CRBG that also considers a regional source/sink approach that is responsive to stakeholder needs and industrial demand. Specific institutional objectives are: (1) identifying and developing plans to mitigate the nontechnical challenges associated with the build-out of a commercial-scale storage complex within the CRBG with integrated CO2 sources; (2) implementing the community outreach plan; (3) conducting regulatory research, including a survey of issues related to pore space ownership, MVA and long-term assurance of mineralization-based storage, to support an eventual application for a UIC Class VI permit; (4) advancing the project’s plan for CO2 liability management; and (5) continuing to refine and update the project’s economic model. The final objective is the preparation of a comprehensive Site Characterization Plan that draws upon the technical and institutional feasibility assessments to prepare the project for future commercialization efforts.

58 GEOSCIENCES↗
DOE OSTI2024

Machine Learning-Driven Quantification of CO2 Plume Dynamics at Illinois Basin Decatur Project Sites Using Microseismic Data

This study utilizes machine learning to quantify CO2 plume extents by analyzing microseismic data from the Illinois Basin Decatur Project (IBDP). Leveraging a unique dataset of well logs, microseismic records, and CO2 injection metrics, this work aims to predict the temporal evolution of subsurface CO2 saturation plumes. The findings illustrate that machine learning can predict plume dynamics, revealing vertical clustering of microseismic events over distinct time periods within certain proximities to the injection well, consistent with an invasion percolation model. The buoyant CO2 plume partially trapped within sandstone intervals periodically breaches localized barriers or baffles, which act as leaky seals and impede vertical migration until buoyancy overcomes gravity and capillary forces, leading to breakthroughs along vertical zones of weakness. Between different unsupervised clustering techniques, K-Means and DBSCAN were applied and analyzed in detail, where K-means outperformed DBSCAN in this specific study by indicating the combination of the highest Silhouette Score and the lowest Davies–Bouldin Index. The predictive capability of machine learning models in quantifying CO2 saturation plume extension is significant for real-time monitoring and management of CO2 sequestration sites. The models exhibit high accuracy, validated against physical models and injection data from the IBDP, reinforcing the viability of CO2 geological sequestration as a climate change mitigation strategy and enhancing advanced tools for safe management of these operations.

Iyegbekedo, Ikponmwosa↗
DOE OSTI2024

Progress of Gas Injection EOR Surveillance in the Bakken Unconventional Play—Technical Review and Machine Learning Study

Although considerable laboratory and modeling activities were performed to investigate the enhanced oil recovery (EOR) mechanisms and potential in unconventional reservoirs, only limited research has been reported to investigate actual EOR implementations and their surveillance in fields. Eleven EOR pilot tests that used CO2, rich gas, surfactant, water, etc., have been conducted in the Bakken unconventional play since 2008. Gas injection was involved in eight of these pilots with huff ‘n’ puff, flooding, and injectivity operations. Surveillance data, including daily production/injection rates, bottomhole injection pressure, gas composition, well logs, and tracer testing, were collected from these tests to generate time-series plots or analytics that can inform operators of downhole conditions. A technical review showed that pressure buildup, conformance issues, and timely gas breakthrough detection were some of the main challenges because of the interconnected fractures between injection and offset wells. The latest operation of co-injecting gas, water, and surfactant through the same injection well showed that these challenges could be mitigated by careful EOR design and continuous reservoir monitoring. Reservoir simulation and machine learning were then conducted for operators to rapidly predict EOR performance and take control actions to improve EOR outcomes in unconventional reservoirs.

Energy & Fuels↗
NASA NTRS1997

The Cretaceous-Tertiary Impact Crater and the Cosmic Projectile that Produced it

Evidence gathered to date from topographic data, geophysical data, well logs, and drill-core samples indicates that the buried Chicxulub basin, the source crater for the approximately 65 Ma Cretaceous-Tertiary (K/T) boundary deposits, is approximately 300 km in diameter. A prominent topographic ridge and a ring of gravity anomalies mark the position of the basin rim at approximately 150 km from the center. Wells in this region recovered thick sequences of impact-generated breccias at 200-300 m below present sea level. Inside the rim, which has been severely modified by erosion following impact, the subsurface basin continues to deepen until near the center it is approximately 1 km deep. The best planetary analog for this crater appears to be the 270 km-diameter Mead basin on Venus. Seismic reflection data indicate that the central zone of downward displacement and excavation (the transient crater is approximately 130 km in diameter, consistent with previous studies of gravity anomaly data). Our analysis of projectile characteristics utilizes this information, coupled with conventional scaling relationships, and geochemical constraints on the mass of extraterrestrial material deposited within the K/T boundary layer. Results indicate that the Chicxulub crater would most likely be formed by a long-period comet composed primarily of nonsilicate materials (ice, hydrocarbons, etc.) and subordinate amounts (less than or equal to 50 percent) primitive chondritic material. This collision would have released the energy equivalent to between 4 x 10(exp 8) and 4 x 10(exp 9) megatons of TNT. Studies of terrestrial impact rates suggest that such an event would have a mean production rate of approximately 1.25 x 10(exp -9) y(exp -1). This rate is considerably lower than that of the major mass extinctions over the last 250 million years (approximately 5 x 10(exp -7) y(exp -1). Consequently, while there is substantial circumstantial evidence establishing the cause-effect link between the Chicxulub basin forming event and the K/T biological extinctions, the results of our analysis do not support models of impact as a common or singular causative agent of mass extinctions on Earth.

Sharpton, Virgil L.↗
DOE OSTI2022

Supplemental Material: Cretaceous sequence stratigraphy of the northern Baltimore Canyon Trough: Implications for basin evolution and carbon storage

We focus on potential reservoirs in the Logan Canyon Formation. Based on lithostratigraphy, Libby-French originally divided the Logan Canyon sandstones into lower and upper Logan Canyon sandstone units separated by the Sable Shale equivalent. Miller et al. reinterpreted the well-log correlations with biostratigraphy using a sequence stratigraphic approach and found three distinct Logan Canyon highstand sandstones associated with three Aptian to lower Cenomanian stratigraphic sequences, the LC3, LC2, and LC1, respectively. In addition, Miller et al. found that the Sable Shale Formation identified by Libby-French was placed above and below the LC1 basal sequence boundary in some wells, highlighting issues with correlating units based only on lithology. The Upper Cretaceous strata in the BCT are termed the Dawson Canyon Equivalent Formation, correlate to the DCx composite sequence, and cap the Logan Canyon sequences below made up of a very thick, calcareous Cretaceous sequence stratigraphy mudstone, divided by a single, thick, laterally continuous Coniacian to Campanian sandstone called the Middle Sandstone.

58 GEOSCIENCES↗
DOE OSTI2017

Liquid-Rich Shale Potential of Utah’s Uinta and Paradox Basins: Reservoir Characterization and Development Optimization

The enclosed report is the culmination of a multi-year and multi-faceted research project investigating Utah’s unconventional tight oil potential. From the beginning, the project team focused efforts on two different plays: (1) the basal Green River Formation’s (GRF) Uteland Butte unconventional play in the Uinta Basin and (2) the more established but understudied Cane Creek shale play in the Paradox Basin. The 2009-2014 high price of crude oil, coupled with lower natural gas prices, generated renewed interest in exploration and development of liquid hydrocarbon reserves. Following the success of the mid-2000s shale gas boom and employing many of the same well completion techniques, petroleum companies started exploring for liquid petroleum in shale formations. In fact, many shales targeted for natural gas include areas in which the shale is more prone to liquid production. In Utah, organic-rich shales in the Uinta and Paradox Basins have been the source of significant hydrocarbon generation, with companies traditionally targeting the interbedded sands or carbonates for their conventional resource recovery. Because of the advances in horizontal drilling and hydraulic fracturing techniques, operators in these basins started to explore the petroleum production potential of the shale units themselves. The GRF in the Uinta Basin has been studied for over 50 years, since the first hydrocarbon discoveries. However, those studies focused on the many conventional sandstone reservoirs currently producing oil and gas. In contrast, less information was available about the more unconventional crude oil production potential of thinner carbonate/shale units, most notably the basal Uteland Butte member. The Cane Creek shale of the Paradox Basin has been a target for exploration periodically since the 1960s and produces oil from several small fields. The play generated much interest in the early 1990s with the successful use of horizontal drilling. Recently, the USGS assessed the undiscovered oil resource in the Cane Creek shale of the Paradox Basin at 103 million barrels at a 95 percent confidence level and 198 million barrels at a 50 percent confidence level. Nonetheless, limited research was available or published to further define the play and the reservoir characteristics. The specific objectives of the enclosed research were to (1) characterize geologic, geochemical, and geomechanical rock properties of target zones in the two designated basins by compiling data and by analyzing available cores, cuttings, and well logs; (2) describe outcrop reservoir analogs of GRF plays (Cane Creek shale is not exposed) and compare them to subsurface data; (3) map major regional trends for targeted intervals and identify “sweet spots” that have the greatest oil potential; (4) reduce exploration costs and drilling risks, especially in environmentally sensitive areas; (5) improve drilling and fracturing effectiveness by determining optimal well completion design; and (6) reduce field development costs, maximize oil recovery, and increase reserves. These objectives are all addressed in a series of nine publications that resulted from this extensive research project. Each publication is included in this report as an independent appendix.

02 PETROLEUM↗
DOE OSTI2023

Field Results from New Tensor Borehole Optical Fiber Strainmeter Installations in Oklahoma and Utah

The time evolving strain field contains a wealth of information that can be used to interpret subsurface behavior. For example, injecting or removing fluids from reservoirs or aquifers causes deformation that can be used as a diagnostic signal in some cases, while it can interfere with geodetic interpretations in other cases. We've previously demonstrated the feasibility of measuring the strain tensor at a depth of 30m caused by injection into a reservoir at 530m. The observed strain signals were interpreted using four independent analytic and numerical methods that resulted in estimates of the poroelastic properties and geometry of the reservoir that was consistent with data from well logs. However, studies like these are only possible if these deformations can be reliably measured. Years of lab and field work has culminated in the development of a novel borehole strainmeter capable of resolving multiple components of strain using embedded optical fibers configured as Michelson interferometers. It features four horizontal gauges separated by 45° to resolve the horizontal strain tensor as well as a vertical strain gauge and a sixth null component for state-of-health monitoring. The downhole sensing package also includes an open pipe through its center for grout circulation during single-trip deployments and a fully welded stainless steel exterior for robustness and longevity. These instruments have a resolution of 2x10-13 strain that can easily measure the solid earth tides. Preliminary data are available from four strainmeters in shale at our Oklahoma site and four in compacted sand and gravel in Utah. These are deployed from 40-60m, except one of the strainmeters in Oklahoma is deployed at 500m. The data include strains from the initial grout curing, comparisons to predicted earth tide models and in-situ calibration results, barometric pressure admittances and spectral analyses as well as signals from underground injections and surface waves from teleseismic events. Preliminary analyses indicate behavior consistent with other strainmeter deployments, and comparison to data from a Gladwin strainmeter at the Oklahoma site validate the performance of the new design. Analyses from a suite of six well tests at the Oklahoma site show for the first time how the strain tensor field varies with location during well testing.

DeWolf, Scott↗
DOE OSTI2020

Charged Wellbore Casing Controlled Source Electromagnetics (CWC-CSEM) for Reservoir Imaging and Monitoring (Final report)

This project addresses the needs of the U.S. Department of Energy (DOE) to develop advanced monitoring technologies and protocols to track the fate of subsurface carbon dioxide (CO2) plumes for carbon storage. Specifically, the project seeks to develop and test a unique and novel system of technologies consisting of electromagnetic data acquisition, coupled multiphysics imaging, and reservoir model enhancement to understand the migration and long-term distribution of CO2 in the subsurface. The overarching objective is to develop an integrated approach for long term monitoring of carbon storage. The two main components of the project include the methodology development and the test of the method at a field site. The methodology component consists of 1) developing the field procedure and protocol for collecting time-lapse controlled-source electromagnetic (CSEM) data with source electric current injected into the subsurface through wellbore casings; 2) building of background 3D electrical conductivity utilizing multiple sources of data such as supplemental surface transient EM (TEM) surveys, well-logs, and seismic structural information, for enhancing CSEM signal from reservoir depths; and 3) coupled multiphysics simulations and inversion of CSEM data constrained by production data and by structural information from seismic imaging of the reservoir and overlying formations. The testing component used the field site of Bell Creek Oil Field, which served both as a field laboratory for the method development as well as a test site to evaluate the CSEM signal strengths and the methodology developed in this research project. We have accomplished all the proposed tasks and developed the methodology as planned. These include the procedure for time-lapse CSEM data acquisition, data processing techniques, integration with 3D conductivity model building, fast reservoir simulation for history matching using machine learning, and interpreting CSEM data with coupling to the reservoir modeling. Collectively, the outcome of these tasks form a coherent workflow that can be applied to monitor dedicated carbon storage in saline reservoirs. The testing component evaluated the applicability and limitations of the method, and concluded that the method would be ideal for monitoring dedicated carbon storage sites utilizing saline reservoirs.

54 ENVIRONMENTAL SCIENCES↗
DOE OSTI2016

A method to improve the sensitivity of neutron porosity measurement based on D-T source

Compensated porosity logging tool utilizing deuterium-tritium (D-T) source shows a lower sensitivity to the variation of formation porosity compared with that adopting Am-Be source. In order to improve the sensitivity, the factors of an infinite homogeneous formation influencing slowing-down length and the near to far counts ratio are analyzed in this paper. Then Monte Carlo simulation method is used to build well logging models to study the responses of a neutron porosity logging tool to hydrogen index and formation density. It shows that in addition to hydrogen index, the variation of the density also has a great impact on slowing-down length and the ratio which reduces the response sensitivity to porosity. A new model depicts the relationship between the count ratio and porosity is proposed. Finally, when the model is used to process the measured ratio, the ratio shows improved dynamic range and sensitivity to porosity compared with the values without processing.

47 OTHER INSTRUMENTATION↗
DOE OSTI2018

Integrated Geologic Storage Prefeasibility Study Proximal to Dry Fork Power Station, Powder River Basin, Wyoming

The pre-feasibility study—funded by the Department of Energy CarbonSAFE program (DE-FE0029375)—is centred around Basin Electric’s Dry Fork Station (DFS) in Wyoming’s Powder River Basin. Dry Fork Station, completed in 2011, is a high efficient coal-fired power plant that emits 3.3 million tons of CO2 per annum. The DFS site also host’s the Wyoming Integrated Test Center (ITC) funded by a $15 million investment by the State of Wyoming. The ITC is a public-private partnership test bed for CCS technologies. Geologic storage sites are in immediate vicinity of the DFS providing significant opportunities for co-located source and saline storage. The Powder River Basin (PRB) of Wyoming and Montana, was identified by NETL (2010) as having a “high potential” for commercial-scale carbon sequestration. The basin contains as much as 17,000 feet of sedimentary rock and covers an area of approximately 24,000 square miles. The PRB has a long history of hydrocarbon production and remaining undiscovered reserves. Accumulations and production of hydrocarbons in the basin indicate the presence of reservoir formations with significant pore volumes and impermeable sealing formations. This attribute alone suggests the reservoir and seal characteristics of the formations provide significant opportunities for CO₂ storage in saline reservoirs. Four high quality potential reservoir and sealing complexes have been identified for geologic storage. These formations range in depth from 6,500-9,500 feet underneath DFS including: (1) the Pennsylvanian Minnelusa Formation reservoir and Permian Goose Egg Formation (Opeche Shale) seal; (2) the Jurassic Hulett and Canyon Springs Sandstones of the Sundance Formation sealed by the Late Jurassic Upper Sundance Member and Morrison Formation and (3) the Early Cretaceous Lakota and Dakota, and Muddy Formation reservoirs sealed by the Mowry Shale. The preliminary reservoir characterization results integrate data from petrophysical well logs, core measurements, faults/fractures analysis, artificial penetrations, and published literature to evaluate geologic storage capacity and potential risk, for the Powder River Basin. These reservoir and seal combinations reside within ideal depth constraints and show suitable reservoir and seal characteristics conducive to commercial-scale storage. Specifically, this paper presents 1) high level description of the geologic storage complex 2) a first order risk analysis associated with pre-existing oil and gas wells, and 3) preliminary storage capacity and Area of Review estimates.

Quillinan, Scott↗
DOE OSTI2020

Characterization of Carbon Sequestration Targets of the Mid-Atlantic Coastal Plain and Adjacent Offshore Region

Lower to mid-Cretaceous age rock formations were identified on the onshore Mid-Atlantic U.S. Coastal Plain and offshore northern Baltimore Canyon Trough (BCT) that show great potential as reservoirs for carbon sequestration. These targets are constrained using a sequence stratigraphic approach by integration of multi-channel seismic, geophysical well-log, core, and biostratigraphic datasets. In the onshore coastal plain of New Jersey, Delaware, and Maryland, the Lower Cretaceous Waste Gate Formation and mid-Cretaceous Potomac Formation/Group were divided into three major sequences (Waste Gate-Potomac Unit I, Potomac Unit II, and Potomac Unit III). The analysis concluded that Waste Gate-Potomac Unit I sequence is most suitable for carbon storage, as it has thick, correlatable sands in New Jersey and Maryland that are well confined in New Jersey, and could store potentially large volumes of CO2 (~ 8-34 Gt). In the offshore, we evaluate the mid-Cretaceous Logan Canyon Formation which we divide into three sequences (LC3, LC2, and LC1). All three sequences show potential for large volumes of CO2 storage (~5.9 Gt on the Great Stone Dome (GSD); preliminary volume estimates in the MRCSP ATLAS are currently being updated by MAOCSRAP). The Logan Canyon Sands are an excellent target for carbon storage in the offshore Baltimore Canyon Trough; they are thick, correlatable sands with high permeabilities and porosities, and are confined by the thick Dawson Canyon Shale. Sands are particularly thick, porous, and very permeable in wells on the GSD, which provides a great structural trap, and as such is a world-class target for carbon sequestration.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2022

Assessing Impacts on Pressure Stabilization and Leasing Acreage for CO 2 Storage Utilizing Oil Migration Concepts

Favorable geological storage for CO 2 has long been pictured as large anticlines with thick sandstones, similar to oil reservoirs in the petroleum system. Unlike oil, however, stored CO 2 does not need to be recoverable, which raises the possibility of using dissolution and residual trapping to augment the capacity of buoyant traps and tap more of the bulk rock volume. The work presented builds on that idea, asking the following question: If we inject CO 2 down to a syncline – analogous to the carrier bed in the petroleum system – how would this injection mechanism impact storage capacity and plume shape, migration, and stabilization? To address this question, we built a reservoir model, based on seismic interpretation of Middle Miocene strata, offshore Galveston, Texas. 3-D seismic and well logs were used to characterize key intervals. Reservoirs chosen for modeling are progradational-aggradational sands with mud intercalation. They have a higher degree of heterogeneity than the more conventional reservoirs commonly targeted for CO 2 storage. Modeling investigated how far the CO 2 plume would migrate under two scenarios: (1) injecting CO 2 at the base of the salt withdrawal basin (syncline scenario) and (2) injecting CO 2 at the base of the structural closure, similar to a common injection well location for EOR purposes (base scenario). For each scenario, we separately simulated injection of 30 MT of CO 2 and 60 MT of CO 2 continuously for 30 years and observe the plume and pressure evolution for 100 years after the injection stops. The simulation shows that injecting the CO 2 into a syncline limits the vertical migration of CO 2 , thus making synclinal injection more secure. In the syncline scenario, the geological layer around the injection point is more heterogeneous than the layer in the base scenario; thus, the CO 2 tends to migrate laterally. Additionally, in the syncline scenario, the plume does not even reach the upper part of the anticline, allowing us to safely store an additional amount of CO 2 into the reservoir. Furthermore, the simulation also shows that in the syncline scenario, the times needed for the reservoir to reach its stabilized pressure after the end of injections are faster. To summarize, CO 2 injection at the base of a syncline could provide additional storage, increase the safety of the project from the limited vertical plume migration, and expedite plume stabilization, which could result in the decrease of monitoring frequency as the project runs, thus lowering the operating cost of the project in the long run.

58 GEOSCIENCES↗
NASA NTRS1988

The Calvin 28 cryptoexplosive disturbance, Cass County, Michigan: Evidence for impact origin

The Calvin 28 cryptoexplosive disturbance is an isolated, nearly circular subsurface structure of Late Ordovician age in southwestern Michigan. The structure is defined by 107 wells, is about 7.24 km in diameter and consists of a central dome, an annular depression and an encircling anticlinal rim. Seismic and geophysical well log data confirm that an intricate system of faults and structural derangement exists within the structure. Deformation decreases with depth and distance from the structure. U.S.G.S. topographic maps and aerial imagery show the structure is reflected as a subtle surface topographic rise controlling local drainage. Igneous or diapiric intrusion and solution collapse are rejected as possible origins for Calvin 28 on the basis of stratigraphic, structural and geophysical evidence. A volcanic origin is inconsistent with calculated energy requirements and an absence of igneous material. Although shock-metamorphic features are unidentified, microbreccias occur in deep wells that penetrate the structure. Morphology and structural parameters support an impact origin.

Milstein, Randall L.↗
DOE OSTI2018

Resource Analysis for Deep Direct-Use Feasibility Study in East Texas

The National Renewable Energy Laboratory, Southern Methodist University Geothermal Laboratory, Eastman Chemical, Turbine Air Systems, and the Electric Power Research Institute are evaluating the feasibility of using geothermal heat to improve the efficiency of natural gas power plants. The area of interest is the Eastman Chemical plant in Longview, Texas, which is on the northwestern margin of the Sabine Uplift. The study is focused on determining the potential for a geothermal reservoir within a 10 km radius of the site as defined by data from existing geological studies and cross-sections within the depths of 2,100 to 3,400 meters. Wells within a 20 km radius are included for broader geological comparison to determine the heat flow, temperature-at-depth, and oil and gas field porosity and permeability. The geothermal reservoir model is based on the multiple formation top data sources, published literature data, and well log interpretations within the 10 km radius. Area thickness estimates, reservoir extent bounding parameters, potential flow rates, and temperatures are combined to calculate a reservoir productivity index and develop a reservoir production model. Historical fluid volumes production data are used as an independent check for the reservoir productivity index and production model results. The reservoir parameters calculated here are being used for the surface engineering model to determine the economic viability of using geothermal fluids for a deep direct use application at this site. The data files are submitted as separate workbooks in 'content model' format, including: Well Fluid Production, Heat Flow, and Geologic Reservoir.

15 GEOTHERMAL ENERGY↗
DOE OSTI2017

Structural and Stratigraphic Controls on Methane Hydrate occurrence and distribution: Gulf of Mexico, Walker Ridge 313 and Green Canyon 955: Final Report

The goal of this project was to determine structural and stratigraphic controls on hydrate occurrence and distribution in Green Canyon (GC) 955 and Walker Ridge (WR) 313 blocks using seismic and well data. Gas hydrate was discovered in these blocks in coarse- and fine-grained sediments during the 2009 Joint Industrial project (JIP) Leg 11 drilling expedition. Although the immediate interest of the exploration community is exclusively hydrate which is present in coarse–grained sediments, factors that control hydrate and free gas distribution in the two blocks and whether coarse and fine-grained hydrate-bearing units are related in any manner, formed the core of this research. The project spanned from 10/01/2012 to 07/31/2016. In the project, in both the leased blocks, the interval spanning the gas hydrate stability zone (GHSZ) was characterized using a joint analysis of sparse Ocean Bottom Seismic (OBS) and dense, surface–towed multichannel seismic (MCS) data. The project team had the luxury of calibrating their results with two well logs. Advance processing methods such as depth migration and full-waveform inversion (FWI) were used for seismic data analysis. Hydrate quantification was achieved through interpretation of the FWI velocity field using appropriate rock physics models at both blocks. The seismic modeling/inversion methodology (common to both GC955 and WR313 blocks) was as follows. First, the MCS data were depth migrated using a P-wave velocity (VP) model constructed using inversion of reflection arrival times of a few (four in both cases) key horizons carefully picked in the OBS data to farthest possible offsets. Then, the resolution of the traveltime VP model was improved to wavelength scale by inverting OBS gathers up to the highest frequency possible (21.75 Hz for GC955 and 17.5 for WR313) using FWI. Finally, the hydrate saturation (or the volume fraction) was estimated at the well location assuming one of the other hydrate morphology (filling the primary or the secondary porosity) was extrapolated out from the wells using the FWI VP as a guide. General outcomes were as follows. First and foremost, an imaging methodology using sparse seismic data, which is easily replicable at other sites with similar datasets, has been demonstrated. The end product of this methodology at both the leased blocks is quantitative estimates of hydrate distribution. Second, at both locations there is strong evidence that the base of the GHSZ, which does not appear as a clear Bottom Simulating Reflection (BSR), manifests in the VP perturbations created by FWI, suggesting that FWI is sensitive to subtle compositional changes in shallow sediments and establishes it as a valuable tool for investigations of hydrate-bearing basins. Third, through joint interpretation of the depth migrated image and the FWI VP model, how structure and stratigraphy jointly determine hydrate and free gas distribution in both blocks could be clearly visualized. The joint interpretation also suggests that the coarse and fine grained hydrate-bearing sediments at both leased are connected. Site specific results, in addition to general results, are as follows. At GC955 the overlying fine-grained hydrate-bearing unit could have been sourced from the underlying hydrate coarse-grained channel-levee complex through a chimney feature. The channel-levee system at GC955 is compartmentalized by faults, of which only a few may be impermeable. Although compartmentalized, the channel-levee system in the GC955 as a whole might be in communication except selected zones. At WR313 the overlying fine-grained fracture-filled hydrate unit appears to be sourced from below the GHSZ. The reason that only a particular fine-grained unit has hydrate, despite having lower porosity that the bounding units, could be the presence of secondary porosity (such as those formed from clay dewatering under compaction). In conclusion, the project was a pioneering effort in in joint analysis of OBS and MCS datasets for advancing the knowledge about a hydrate and free–gas system dynamics using advanced processing methods such as FWI and depth migration. Results obtained in this project can greatly advance the tools and techniques used for delineating specific hydrate prospects. Results obtained in this project can also be seamlessly incorporated into other DOE funded project on modeling the potential productivity and commercial viability of hydrate from sand-dominated reservoirs. The OBS and MCS data in this project were acquired in 2012 (after the JIP II drilling) by the USGS and therefore the results are a posteriori. Nonetheless, the seismic inversion workflow established through this project can be used to generate various what-if quantification scenarios even in absence of logs and serve as a valuable tool for guiding drilling operations. Results from this project can augment other DOE sponsored projects on determining the commercial viability of methane production from the Gulf of Mexico.

03 NATURAL GAS↗
DOE OSTI2017

Well Monitoring System For EGS

This grant is a collection of projects designed to move aircraft high temperature electronics technology into the geothermal industry. Randy Normann is the lead. He licensed the HT83SNL00 chip from Sandia National Labs. This chip enables aircraft developed electronics for work within a geothermal well logging tool. However, additional elements are needed to achieve commercially successful logging tools. These elements are offered by a strong list of industrial partners on this grant as: Electrochemical Systems Inc. for HT Rechargeable Batteries, Frequency Management Systems for 300C digital clock, Sandia National Labs for experts in high temperature solder, Honeywell Solid-State Electronics Center for reprogrammable high temperature memory. During the course of this project MagiQ Technologies for high temperature fiber optics.

15 GEOTHERMAL ENERGY↗
DOE OSTI2014

Experimental design applications for modeling and assessing carbon dioxide sequestration in saline aquifers

This project was a computer modeling effort to couple reservoir simulation and ED/RSM using Sensitivity Analysis, Uncertainty Analysis, and Optimization Methods, to assess geologic, geochemical, geomechanical, and rock-fluid effects and factors on CO 2 injectivity, capacity, and plume migration. The project objective was to develop proxy models to simplify the highly complex coupled geochemical and geomechanical models in the utilization and storage of CO 2 in the subsurface. The goals were to investigate and prove the feasibility of the ED/RSM processes and engineering development, and bridge the gaps regarding the uncertainty and unknowns of the many geochemical and geomechanical interacting parameters in the development and operation of anthropogenic CO 2 sequestration and storage sites. The bottleneck in this workflow is the high computational effort of reactive transport simulation models and large number of input variables to optimize with ED/RSM techniques. The project was not to develop the reactive transport, geomechanical, or ED/RSM software, but was to use what was commercially and/or publically available as a proof of concept to generate proxy or surrogate models. A detailed geologic and petrographic mineral assemblage and geologic structure of the doubly plunging anticline was defined using the USDOE RMOTC formations of interest data (e.g., Lower Sundance, Crow Mountain, Alcova Limestone, and Red Peak). The assemblage of 23 minerals was primarily developed from literature data and petrophysical (well log) analysis. The assemblage and structure was input into a commercial reactive transport simulator to predict the effects of CO 2 injection and complex reactions with the reservoir rock. Significant impediments were encountered during the execution phase of the project. The only known commercial reactive transport simulator was incapable of simulating complex geochemistry modeled in this project. Significant effort and project funding was expended to determine the limitations of both the commercial simulator and the Lawrence Berkeley National Laboratory (LBNL) R&D simulator, TOUGHREACT available to the project. A simplified layer cake model approximating the volume of the RMOTC targeted reservoirs was defined with 1-3 minerals eventually modeled with limited success. Modeling reactive transport in porous media requires significant computational power. In this project, up to 24 processors were used to model a limited mineral set of 1-3 minerals. In addition, geomechanical aspects of injecting CO 2 into closed, semi-open, and open systems in various well completion methods was simulated. Enhanced Oil Recovery (EOR) as a storage method was not modeled. A robust and stable simulation dataset or base case was developed and used to create a master dataset with embedded instructions for input to the ED/RSM software. Little success was achieved toward the objective of the project using the commercial simulator or the LBNL simulator versions available during the time of this project. Several hundred realizations were run with the commercial simulator and ED/RSM software, most having convergence problems and terminating prematurely. A proxy model for full field CO 2 injection sequestration utilization and storage was not capable of being developed with software available for this project. Though the chemistry is reasonably known and understood, based on the amount of effort and huge computational time required, predicting CO 2 sequestration storage capacity in geologic formations to within the program goals of ±30% proved unsuccessful.

54 ENVIRONMENTAL SCIENCES↗
DOE OSTI2018

Assessment of CO 2 Storage Resources in Depleted Oil and Gas Fields in the Ship Shoal Area, Gulf of Mexico

The Gulf of Mexico is one of the most important regions in the United States for energy resources and infrastructure. Gulf of Mexico federal offshore oil and gas production accounts for 17% of total U.S. crude oil production and 5% of total U.S. gas production (EIA Gulf of Mexico Fact Sheet). This region presents an excellent combination of high need and significant opportunity for large scale geologic storage of CO 2 . The Ship Shoal Area is located about 20 miles offshore Louisiana within the Gulf Coast federal waters. Miocene and Pliocene sediments in the Ship Shoal Area are proven to provide excellent and secure traps for oil and gas. The Ship Shoal Area contains a large number of depleted oil and gas fields either currently abandoned, or planned for abandonment by 2025, which may provide very significant potential CO 2 storage capacity. GeoMechanics Technologies conducted a comprehensive research project to better characterize Neogene sediments in the Ship Shoal Area for high volume CO 2 storage. The data generated from literature, well data, well log, and formation evaluation were input into Rockwork 16 geologic software to create a detailed geologic model for the Ship Shoal study area. The geologic grids were then fed into TOUGH2, the gas migration model software and FLAC 3D, the geomechanical model software. The fluid flow modeling for both the Miocene and Pliocene simulation from both Block 107 and Block 84 indicated that Pliocene and Miocene are a good reservoir for the CO 2 sequestration. Thirty years of CO 2 injection (at a rate of 1 million metric tons CO 2 per year) and 30 years of observation simulations were run with the fluid flow modeling. The 3D geomechanical modeling for Ship Shoal Block 107 and Block 84 were developed to evaluate induced surface deformation and potential fault reactivation after 30 years CO 2 injection at base of Pliocene and at upper Miocene injection locations. Evaluation results indicate low to no risks for fault slips or fault reactivation. Twelve well bores and 76 well bores for Ship Shoal Blocks 84 and 107 respectively were reviewed for their cement history. Most wells (57 out of 76 and 7 out of 12 wells in Ship Shoal Block 107 and 84 respectively) have good integrity. Nineteen and 5 wells (in Ship Shoal Block 107 and 84 respectively) with no top plug, incomplete cement or Plug and Abandonment information are given yellow cautionary indicators. These cautionary wells may provide leakage paths of CO 2 through the well bores to the USDWs. Using our Quantitative Risk & Decision Analysis Tool (QRDAT) for caprock integrity evaluation, we compared Ship Shoal’s risk to that of In Salah, Sleipner, Kevin Dome, Loudon, Illinois Industrial CCS and Wilmington Graben. We found the risk at the Ship Shoal Blocks 84 and 107 fields are similar to the known CO 2 active sequestration sites, but lower than the Wilmington Graben turbidities offshore California studied site. The risk of natural seismicity in the Gulf of Mexico is relatively low. Geomechanics Technologies has documented the top 25 CO 2 emission sources within the close proximity of the Ship Shoal Block 84 and 107 fields. All the offshore and onshore pipelines have been digitized and can be viewed in an interactive website (http://www.geomechanicstech.com/shipshoal.html). We also performed a feasibility study on the potential for converting existing oil or gas pipelines for CO 2 transport. There are abandoned, idled and retired onshore and offshore pipelines. However, there is no standard specification for maximum pipeline pressures needed for CO 2 transport. It is a function of design, materials, and testing provided; thus it will be the responsibility of the pipeline operator to correctly determine, maintain and operate within the limits of the pipelines. There are a few transit corridors extending from onshore Louisiana (Cailou Bay) to offshore trunk-lines. The cost for constructing a pipeline has increased about 46% from 2015 to an average cost of $5,064,046 per mile in 2016. We use the NETL CO 2 storage resource mass estimate to calculate the potential resources for Ship Shoal Block 84 and 107 fields using the depleted oil and gas reservoir volume and sand volume generated from our geologic modeling. The estimated storage resource results are greater when using the sand volumes derived through geologic modeling than the oil and gas reservoir data. The difference is due to the depleted oil and gas reservoir information not accounting for the water-flooded sand located below the oil/gas-water contact or unproductive sand units. Resource calculation using the sand volume obtained through geologic modeling overestimate the storage capacity as the model accounts for all sand within the formation, not just the interconnected sand.

02 PETROLEUM↗