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This report summarizes work conducted in FY2017 to identify and document publically available data for developing a Geologic Framework Model (GFM) for the Deep Borehole Field Test (DBFT). Data was collected for all four of the sites being considered in 2017 for a DBFT site.
Geologic heterogeneity is a key feature that must be considered when translations of scaled data are performed. This paper presents the assessment of geologic heterogeneity using a multiscale workflow that includes image analysis-based methods coupled with well log analysis to provide data in which fractals and machine learning methods estimate the carbon dioxide (CO 2 ) storage resource potential of a reservoir. The heterogeneity of rock properties of the complex Bell Creek reservoir in Montana, USA, was explored at the pore scale (~nm to mm), core scale (~mm to m), and well scale (~cm to m). The data used in this study included advanced image analysis of micro-CT (computed tomography) images (pore scale), thin sections (pore scale), plugs and core images (core scale) and well logs (well scale). The micro-CT images were segmented using a U-net segmentation approach into objects of pores and grains. Further, the segmented images were reconstructed into subvolumes of different sizes. Physical properties (porosity and permeability) and fractal dimensions were calculated for the various subvolumes, and Lorenz coefficient (Lc) values, a single parameter to describe the degree of heterogeneity within a pay zone section, were calculated from thin-section images and well logs. Porosity and fractal dimension values were used to estimate the 188-µm threshold of representative elementary volume (REV) in this study. Both the Lc and fractal dimension values were found to be negatively correlated. When these two parameters are combined, it is possible to discern differences in the complex porous networks of the samples analyzed in this study.
The first-ever polymer flood pilot to enhance heavy oil recovery on Alaska North Slope (ANS) is ongoing. After more than 2.5 years of polymer injection, significant benefit has been observed from the decrease in water cut from 65% to less than 15% in the project producers. The primary objective of this study is to develop a robust history-matched reservoir simulation model capable of predicting future polymer flood performance. In this work, the reservoir simulation model has been developed based on the geological model and available reservoir and fluid data. In particular, four high transmissibility strips were introduced to connect the injector-producer well pairs, simulating short-circuiting flow behavior that can be explained by viscous fingering and reproducing the water cut history. The strip transmissibilities were manually tuned to improve the history matching results during the waterflooding and polymer flooding periods, respectively. It has been found that higher strip transmissibilities match the sharp water cut increase very well in the waterflooding period. Then the strip transmissibilities need to be reduced with time to match the significant water cut reduction. The viscous fingering effect in the reservoir during waterflooding and the restoration of injection conformance during polymer flooding have been effectively represented. Based on the validated simulation model, numerical simulation tests have been conducted to investigate the oil recovery performance under different development strategies, with consideration for sensitivity to polymer parameter uncertainties. The oil recovery factor with polymer flooding can reach about 39% in 30 years, twice as much as forecasted with continued waterflooding. Besides, the updated reservoir model has been successfully employed to forecast polymer utilization, a valuable parameter to evaluate the pilot test’s economic efficiency. All the investigated development strategies indicate polymer utilization lower than 3.5 lbs/bbl in 30 years, which is economically attractive.
Geologic analysis of radar imagery requires accurate spatial rectification to allow rock type discrimination and meaningful exploitation of multisensor data files. A procedure is described which removes distortions produced by most sources including the heretofore elusive problem of terrain induced effects. Rectified imagery is presented which displays geologic features not apparent in the distorted data.
In Germany, a new site selection act for a repository for HLW and SNF entered into force in July 2013 and was amended in spring 2017 [1]. It stipulates that the safety of repository systems for heat-generating radioactive waste and spent nuclear fuel in different host rock formations be compared. This requires that generic repository concepts and adequate safety- and safety demonstration concepts for all potential host rock formations in Germany (salt, clay and crystalline rock) exist. For several decades, development of disposal concepts and safety analyses for a repository in a salt dome was prioritized while repository concepts for clay and crystalline rock have been taken into account for two decades only. So far, bedded salt formations have not been the subject of comparative investigations. Thus, in summer 2015, the Federal Ministry for Economic Affairs and Energy (BMWi) launched the R and D project KOSINA to develop repository designs and carry out safety analyses for different emplacement alternatives in a generic bedded salt formation and a generic salt pillow. KOSINA is an acronym for 'Concept development for a generic repository for heat-generating waste in bedded salt formations in Germany as well as development and testing of a safety and demonstration concept'. Together with its partners BGR, GRS, and IfG, DBE Technology GmbH has successfully carried out an almost three years lasting scientific programme, which will be concluded in April 2018. The core areas of the programme are the development of generic geologic models, including derivation of model parameters, the development of a safety and safety demonstration concept, the development of technical repository designs for four different emplacement alternatives, the analysis of geomechanical integrity, the evaluation of operational safety as well as the analysis of radiological consequences. An interim report, which compiles the basic data of the waste inventory, the repository design requirements, the data basis for geologic model developments, and the outline of a safety and safety demonstration concept, was already published in February 2016. The main achievements of the R and D project KOSINA are the development of four different repository designs, two per each generic geologic model (flat-bedded salt, salt pillow) based on thermomechanical calculations. This includes the implementation of a safety concept that provides containment of the radioactive materials with regard to the technical designs of waste packages, transport and emplacement technologies, and backfilling and sealing concepts. Furthermore, the integrity of the geologic barriers could be demonstrated for all four repository designs, and the long-term predictions showed no radiological releases during the demonstration period of one million years. (authors)
EarthVision 3D model of Newberry Volcano based upon geologic datasets.
Robust geothermal activity in the Great Basin, USA is a product of both anomalously high regional heat flow and active fault-controlled extension. Elevated permeability associated with some fault systems provides pathways for circulation of geothermal fluids. Constraining the local-scale 3D geometry of these structures and their roles as fluid flow conduits is crucial in order to mitigate both the costs and risks of geothermal exploration and to identify blind (no surface expression) geothermal resources. Ongoing studies have indicated that much of the robust geothermal activity in the Great Basin is associated with high density faulting at structurally complex fault intersection/interaction areas, such as accommodation/transfer zones between discrete fault systems, step-overs or relay ramps in fault systems, intersection zones between faults with different strikes or different senses of slip, and horse-tailing fault terminations. These conceptualized models are crucial for locating and characterizing geothermal systems in a regional context. At the local scale, however, pinpointing drilling targets and characterizing resource potential within known or probable geothermal areas requires precise 3D characterization of the system. Employing a variety of surface and subsurface data sets, we have conducted detailed 3D geologic analyses of two Great Basin geothermal systems. Using EarthVision (Dynamic Graphics Inc., Alameda, CA) we constructed 3D geologic models of both the actively producing Brady’s geothermal system and a ‘greenfield’ geothermal prospect at Astor Pass, NV. These 3D models allow spatial comparison of disparate data sets in 3D and are the basis for quantitative structural analyses that can aid geothermal resource assessment and be used to pinpoint discrete drilling targets. The relatively abundant data set at Brady’s, ~80 km NE of Reno, NV, includes 24 wells with lithologies interpreted from careful analysis of cuttings and core, a 1:24,000 scale detailed geologic map and cross-sections, 2D seismic reflection profiles and other geophysical data, and downhole temperature data. The 3D geologic model based on these data consists of 61 fault planes, 25 distinct stratigraphic units, and 2 intrusive bodies. Geothermal fluids are produced from a left step-over/relay ramp within the Brady’s Fault Zone (BFZ). Under local stress conditions, fault segments that strike NNE-to-NE are most likely to slip and/or dilate, and therefore transmit geothermal fluids. The 3D model defines the locations of discrete fault intersections within the BFZ and indicates that the densest zones of structurally controlled fracture permeability are ~10-to-10s of meters in diameter and plunge ~55° NW-NNW beneath the heart of the BFZ step over. The locations of high intersection density, high fault slip and dilation tendency, high subsurface temperature, and lithologies known to support high fracture permeability are combined to produce 3D ‘fairway’ maps useful in both assessments of geothermal resource potential and for defining drilling targets. Astor Pass is located on the Pyramid Lake Paiute Reservation, ~80 km north of Reno, NV. It is a prospective ‘greenfield’ geothermal area, and thus subsurface data are relatively sparse. Available data include: two relatively deep wells (~1400 m) and one shallower well (~500 m) with lithologies interpreted from drill cuttings, several 2D seismic reflection profiles, a 1:24,000 scale geologic map and cross-section, a shallow temperature survey, and downhole temperature data. 3D modeling based on these data has defined 19 distinct fault planes and 16 stratigraphic units. Based on the stress field calculated from borehole breakouts, drilling induced tensile cracks and petal-centerline cracks in the two relatively deep wells, 3D slip and dilation tendency analysis indicates that northerly striking fault segments are most likely to slip and/or dilate, and therefore transmit geothermal fluids. Analysis of fault intersection density indicates that the highest density of structurally controlled permeability within the field lies in a narrow (10-to-10s of m) zone plunging moderately (~35°) to the NNW beneath Pleistocene tufa deposits. This zone of increased fracture density, which we interpret as the primary upflow zone, is controlled by the intersection of N-to-NNW striking normal faults and a WNW striking dextral fault zone and represents the most promising target for future drilling. Construction of a 3D geologic model involves integration of a variety of data into an internally consistent framework. A robust model allows for spatial comparison between the various types of data (structural, stratigraphic, geophysical, temperature, etc.) that are commonly used independently to site geothermal wells. Furthermore, highly detailed 3D geologic models provide the basis for additional quantitative analysis, including 3D fault slip and dilation tendency analysis and the precise location of structurally controlled permeability pathways. These analyses provide detailed information relating to the internal dynamics of geothermal systems and can mitigate the costs and risks of geothermal exploration and development by contributing to better well targeting and more accurate evaluations of resource potential.
Large-scale carbon sequestration will likely require multiple projects injecting CO 2 into the same subsurface formation, raising concerns about safe operation and efficient use of storage capacity. This study evaluates the long-term response of the Mokelumne River Formation in California’s Sacramento Basin to multi-megaton CO 2 injection using three geologic models of the formation and the open-source simulator GEOS. The analysis focuses on three aspects of reservoir performance: (1) average pressure increase and dissolved CO 2 mass after 30 years for varying well counts and injection rates, (2) pressure interference in a multi-well configuration, and (3) dynamic storage capacity with identification of overpressure-prone regions. The results show that average formation pressure increases linearly with injected mass, while CO 2 dissolution exhibits mixed scaling: approximately linear with the number of wells but sublinear with injection rate, indicating that distributing injection across more wells enhances dissolution more effectively than increasing per-well rates. Pressure-interference effects are significant, with lower-permeability conditions delaying their onset but amplifying their magnitude at later times. Dynamic capacity, defined by the first occurrence of pressure exceeding the local overburden-based limit anywhere in the formation, varies across geologic models and assumed overburden pressure gradients. A lower fidelity geologic model predicts nearly twice the storage capacity of the two higher fidelity models, which consistently estimate approximately 1 Gt under the upper-bound overburden pressure gradient considered for the Sacramento Basin. In all model scenarios, overpressure develops away from injection wells, particularly in higher-elevation regions, highlighting the importance of basin-scale modelling for identifying risks beyond the immediate well vicinity.
These resources provide the full set of cost modeling results and methods as part of the I-WEST Roadmap Initiative that were used to compile figures as part of the "Pathways to CO2 Utilization and Storage for the Intermountain West Region" chapter. The data were generated from a series of National Energy Technology Laboratory (NETL) cost models and relate to carbon dioxide (CO2) transport costs, CO2 enhanced oil recovery (CO2-EOR) economics, and saline storage economics. These models were used to analyze various business cases given changes in technical and financial assumptions for the I-WEST region as a means to explore how these assumptions influence CO2 transport and storage costs, as well as to evaluate the effect of changing oil prices on the viability of CO2-EOR and the mass of CO2 stored via CO2-EOR. The accompanying report titled "Intermountain West Energy Sustainability & Transitions Initiative: CO2 Transport and Geologic Storage Modeling Results" provides a detailed overview on the models, assumptions, and parameters used in the modeling, as well as example results..
Abstract The SWP project is located in a mature waterflood undergoing conversion to CO2-WAG operations in the Farnsworth, Texas, USA. Anthropogenic CO2 is sourced from a fertilizer and an ethanol plant. This work utilizes Farnsworth’s full-field, history-matched, compositional hydrodynamic coupled geomechanical model for assessing the impact of stress changes observed through the history matched field life. Production and injection induced stress changes, fault stability and caprock integrity investigations are performed to project the potential for fault reactivation and the loss of caprock integrity under shear failure. A static mechanical earth model (MEM) was constructed for use in transient coupled geomechanical model based on the existing Southwest Regional Partnership (SWP) geological model. The static MEM inherits the stratigraphic and structural features of the geologic model and incorporates additional overburden, underburden, and sideburden formations required to impose mechanical boundary conditions. Mechanical properties were distributed in the 3D MEM through integration of geophysical logs and 3-dimensional seismic elastic inversion properties using a combination of Bayesian and stochastic interpolation methods. These data are further enhanced by lab derived strength and failure criteria for the caprock interval. Additionally, interpreted faults and other geological features were included as part of the static structural framework to fully represent subsurface hydraulic and mechanical systems and appropriately integrate heterogeneity. Two-way coupling of hydrodynamic flow and geomechanical simulations incorporates the Kozeny-Carman relationship for updating permeability and is history matched through primary, secondary (waterflooding) and tertiary (CO2 WAG) recovery periods before performing a twenty year forecast. Two-way simulations are performed to understand the effective stress perturbations imposed by field operations: water injection and the more recent implementation of WAG. Evaluation of Mohr circles with liquid production and field pressure charts as well as slip tendency and distance to failure metrics indicate that neither our faults or cap rock are critically stressed. This paper presents the results of the Farnsworth initial attempts to integrate the seismic driven 3D MEM into coupled hydrodynamic geomechanical history match simulation workflow.
The objectives of this project are to understand the processes that occur when a maximum of 70,000 metric tonnes of CO 2 are injected into two different formations to evaluate the response in different lithofacies and depositional environments. The evaluation will be accomplished through the use of both in situ and indirect MVA (monitoring, verification, and accounting) technologies. The project will optimize for carbon storage accounting for 99% of the CO 2 using lab and field testing and comprehensive characterization and modeling techniques. Site characterization and CO 2 injection should demonstrate state-of-the-art MVA tools and techniques to monitor and visualize the injected CO 2 plume and to refine geomodels developed using nearly continuous core, exhaustive wireline logs, and well tests and a multi-component 3-D seismic survey. Reservoir simulation studies will map the injected CO 2 plume and estimate tonnage of CO 2 stored in solution, as residual gas, and by mineralization and integrate MVA results and reservoir models shall be used to evaluate CO 2 leakage. A rapid-response mitigation plan was developed to minimize CO 2 leakage and provide a comprehensive risk management strategy. The CO 2 was intended to be supplied from a reliable facility and have an adequate delivery and quality of CO 2 . However, several unforeseen circumstances complicated this plan: (1) the initially negotiated CO 2 supply facility went offline and contracts associated with CO 2 supply had to be renegotiated, (2) a UIC Class VI permit proved to be difficult to obtain due to the experimental nature of the project. Both subjects are detailed in separate deliverables attached to this report. The CO 2 enhanced oil recovery (EOR) and geologic storage in Mississippian carbonate reservoir was sucessully deployed. Approximately 20,000 metric tons of CO 2 was injected in the upper part of the Mississippian reservoir to verify CO 2 EOR viability in carbonate reservoirs and evaluate a potential of transitioning to geologic CO 2 storage through EOR. A total of 1,101 truckloads, 19,803 metric tons—an average of 120 tonnes per day—were delivered over the course of injection that lasted from January 9 to June 21, 2016. After cessation of CO 2 injection, the KGS 2-32 well was converted to water injector and continues to operate. CO 2 EOR progression in the field was monitored weekly with fluid level, temperature, and production recording and formation fluid composition sampling. It is important to note that normally, CO 2 EOR pilots are less efficient than commercial operations due to lack of directional and precise well control, lack of surface facilities for CO 2 recycling, and other factors. As a result of this pilot CO 2 injection, the observed incremental average oil production increase was ~68% with only ~18% of injected CO 2 produced back. Decline curve analysis forecasts of additional cumulative oil produced were 32.44M STB to the end of 2027. Wellington Mississippian pilot efficiency by the end of forecast calculations is 11 MCF per barrel of produced oil. Using 32M STB oil production and $1,964,063 cost of CO 2 , CO 2 EOR cost per barrel of oil production is ~$60. Simple but robust monitoring technologies proved to be very efficient in detecting and locating CO 2 . High CO 2 reservoir retentions with low yields within an actively producing field could help to estimate real-world risks of CO 2 geological storage for future projects. The Wellington Field CO 2 EOR was executed in a controlled environment with high efficiency. This case study proves that CO 2 EOR could be successfully applied in Kansas carbonate reservoirs if CO 2 sources and associated infrastructure are available. Recent developments in unconventional resources development in Mid-Continent USA and associated large volume disposal of backflow water and the resulting seismic activity have brought more focus and attention to the Arbuckle Group in southern Kansas. Despite the commercial interest, limited essential information about reservoir properties and structural elements has impeded the management and regulation of disposal, an issue brought to the forefront by recent seismicity in and near areas of large volumes and rates of brine disposal. The Kansas Geological Survey (KGS) collected, compiled, and analyzed available data, including well logs, core data, step rate tests, drill stem tests, 2-D and 3-D seismic data, water level measurements, and others types of data. Several exploratory wells were drilled and core was collected and modern suites of logs were analyzed. Reservoir properties were populated into several site-specific geological models. The geological models illustrate the highly heterogeneous nature of the Arbuckle Group. Vertical and horizontal variability results in several distinct hydro-stratigraphic units that are the result of both depositional and diagenetic processes. During the course of this project, it has been demonstrated that advanced seismic interpretation methods can be used successfully for characterization of the Mississippian reservoir and Arbuckle saline aquifer. Analysis of post-stack 3-D seismic data at the Mississippian reservoir showed the response of a gradational velocity transition. Pre-stack gather analysis showed that porosity zones of the Mississippian and Arbuckle reservoirs exhibit characteristic amplitude versus offset (AVO) response. Simultaneous AVO inversion estimated P- and S-impedances. The 3-D survey gather azimuthal anisotropy analysis (AVAZ) provided information about the fault and fracture network and showed good agreement to the regional stress field and well data. Mississippian reservoir porosity and fracture predictions agreed well with the observed mobility of injected CO 2 in KGS well 2-32. Fluid substitution modeling predicted acoustic impedance reduction in the Mississippian carbonate reservoir introduced by the presence of CO 2 . Seismicity in the United States midcontinent has increased by orders of magnitude over the past decade. Spatiotemporal correlations of seismicity to wastewater injection operations have suggested that injection-related pore fluid pressure increases are inducing the earthquakes. In this investigation, we examine earthquake occurrence in southern Kansas and northern Oklahoma and its relation to the change in pore pressure. The main source of data comes from the Wellington Array in the Wellington oil field, in Sumner County, Kansas, which has monitored for earthquakes in central Sumner County, Kansas, since early 2015. The seismometer array was established to monitor CO 2 injection operations at Wellington Field. Although no seismicity was detected in association with the spring 2016 Mississippian CO 2 injection, the array has recorded more than 2,500 earthquakes in the region and is providing valuable understanding to induced seismicity. A catalog of earthquakes was built from this data and was analyzed for spatial and temporal changes, stress information, and anisotropy information. The region of seismic concern has been shown to be expanding through use of the Wellington earthquake catalog, which has revealed a northward progression of earthquake activity reaching the metropolitan area of Wichita. The stress orientation was also calculated from this earthquake catalog through focal mechanism inversion. The calculated stress orientation was confirmed through comparison to other stress measurements from well data and previous earthquake studies in the region. With this knowledge of the stress orientation, the anisotropy in the basement could be understood. This allowed for the anisotropy measurements to be correlated to pore pressure increases. The increase in pore pressure was monitored through time-lapse shear-wave anisotropy analysis. Since the onset of the observation period in 2010, the orientation of the fast shear wave has rotated 90°, indicating a change associated with critical pore pressure build up. The time delay between fast and slow shear wave arrivals has increased, indicating a corresponding increase in anisotropy induced by pore pressure rise. In-situ near-basement fluid pressure measurements corroborate the continuous pore pressure increase revealed by the shear-wave anisotropy analysis over the earthquake monitoring period. This research is the first to identify a change in pore fluid pressure in the basement using seismological data and it was recently published in the AAAS journal Science Advances (Nolte et al., 2017). The shear-wave splitting analysis is a novel application of the technique, which can be used in other regions to identify an increase in pore pressure. This increasing pore fluid pressure has become more regionally extensive as earthquakes are occurring in southern Kansas, where they previously were absent. These monitoring techniques and analyses provide new insight into mitigating induced seismicity’s impact on society.
The ongoing DOE/GTO funded EGS Collab project aims to stimulate and conduct inter-well flow tests at an intermediate (~10-20 m) in an underground mine in Lead, South Dakota. It is a collaborative initiative where several national laboratories, universities, and other institutions are working together to develop experimental, instrumentation, characterization, and monitoring tools and concepts that could be later employed at a full-scale EGS demonstration FORGE site. In this paper, we describe the development and workflow approach and some preliminary results of earth modeling task for EGS Collab project. We are creating earth models at three different domain scales – EGS Collab, Intermediate, and Large area – using RockWorks 17 software. Local geology, drifts/shafts, and 4850 L boreholes are incorporated in these models. Similarly, available and applicable physical/mechanical properties are also planned to be included in the earth models. Besides providing visualization of the local geology, mine architecture, and bore holes in the test site, the earth modeling task also envision to develop a series of 3-D block models (ASCII files for scattered data/point clouds in the form of X, Y, Z, g) for various physical/mechanical properties of rock. These 3-D block models will provide a consistent baseline value for a parameter of interest to all modeling/simulation groups involved in the EGS Collab project. For this task, we have assembled a preliminary suite of physical/mechanical properties of rocks. Some of the earth modeling results (3-D block models) have been tested by some modeling/simulation team members to test their applicability and for developing additional modeling capability or modifications in RockWorks exported 3-D block models. It is expected that the earth modeling results will be helpful for achieving the overall EGS Collab project objectives.
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.
Conference presentation on hardware acceleration of AI model training, validation, and testing using wafer scale engines, to improve efficiency and effectiveness of carbon management.
We present that in numerical modeling of geological carbon sequestration (GCS), uncertainty quantification (UQ) is usually needed to evaluate the impact of uncertain model parameters on model predictions caused by limited measurements and incomplete knowledge of the parameters. However, UQ for GCS is computationally expensive due to the large ensemble of complex and lengthy model simulations. In this study, we propose an adaptive Kriging method to build a fast-to-evaluate surrogate of the GCS model to alleviate the heavy computational burden. The surrogate model is efficiently generated using a Taylor expansion-based adaptive experimental design algorithm that combines a distance-based exploration criterion and an exploitation criterion to adaptively search for informative training samples. In addition, we analyze the uncertainty brought by substituting the surrogate for the actual simulation model and explore its influence on UQ results. Lastly, our method is demonstrated in a synthetic GCS model and its performance is evaluated in comparison with the conventional Monte Carlo sampling. Results indicate that our method can greatly improve the computational efficiency in UQ and provide an effective and reliable UQ solution with the consideration of surrogate uncertainty.
Gale is an approximately 155 km diameter crater located on the martian dichotomy boundary (5 deg S 138 deg E). Gale is estimated to have formed 3.8 - 3.5 Gya, in the late Noachian or early Hesperian. Mt. Sharp, at the center of Gale Crater, is a crescent shaped sedimentary mound that rises 5.2 km above the crater floor. Gale is one of the few craters that has a peak reaching higher than the rim of the crater wall. The Curiosity rover is currently fighting to find its way across a dune field at the northwest base of the mound searching for evidence of habitability. This study used orbital images and topographic data to refine models for the geologic history of Mt. Sharp by analyzing its morphological features. In addition, it assessed the possibility of a peak ring in Gale. The presence of a peak ring can offer important information to how Mt. Sharp was formed and eroded early in Gale's history.
The initial phase of a program to determine the best interpretation strategy and sensor configuration for a radar remote sensing system for geologic applications is discussed. In this phase, terrain modeling and radar image simulation were used to perform parametric sensitivity studies. A relatively simple computer-generated terrain model is presented, and the data base, backscatter file, and transfer function for digital image simulation are described. Sets of images are presented that simulate the results obtained with an X-band radar from an altitude of 800 km and at three different terrain-illumination angles. The simulations include power maps, slant-range images, ground-range images, and ground-range images with statistical noise incorporated. It is concluded that digital image simulation and computer modeling provide cost-effective methods for evaluating terrain variations and sensor parameter changes, for predicting results, and for defining optimum sensor parameters.