GCCC Theses and Dissertations

Permanent URI for this collectionhttps://hdl.handle.net/2152/122486

This collection is updated quarterly. For the most complete record of theses and dissertations, please see the ETD Collection.


Recent Submissions

Now showing 1 - 20 of 43
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    Sensitivity analysis of carbon dioxide storage in saline aquifers in the presence of a gas cap
    (2010-08-16) Solano, Silvia Veronica; Groat, Charles G.; Nicot, Jean-Philippe, 1958-
    Deep brine-bearing formations contain a significant CO₂ storage potential as they are usually permeable sandstones at depths in which pressure and temperature conditions assure supercritical state for the injected CO₂. When injecting CO₂ in a hydrocarbon-rich area, presence of a gas cap significantly impacts the CO₂ plume behavior. This study focuses on the assessment of the CO₂ plume properties in formations typical of the Gulf Coast area, under the presence of a gas cap and its consequences for long-term storage. The study is prompted by the presence of a large depleted gas cap at Cranfield, Mississippi where CO₂ is being injected for long-term storage. Presence of the gas cap, even depleted, near the injection site provides an exceptional opportunity to investigate an area made of higher compressibility fluids and its impact on reservoir and operational parameters, particularly CO₂ plume behavior. Enhanced gas recovery is not planned within this area. Considerable volumes of native brine are displaced when large amounts of CO₂ are injected, and when this displacement occurs in a closed system, the amount of stored CO₂ will depend solely on the additional pore space available owing to compressibility of the pore structure and fluids. As a result, presence of a gas cap is expected to impact plume characteristics, as well as operational conditions, because of its larger compressibility. A multi-parameter sensitivity analysis, based on a generic reservoir model, was performed to appreciate relevant factors to CO₂ migration under the influence of the nearby gas cap. It was achieved using the compositional reservoir simulator CMG-GEM and allied modules. Main parameters taken into account for the sensitivity analysis included variation in gas cap properties such as: volume, gas composition and gas residual saturation. Additionally, other parameters have been included in this study such as reservoir dip, injector-gas-cap distance, injection pressure, plume asymmetry and horizontal centroid location. The CO₂ plume extends farther as the gas cap volume increases and the distance to the gas cap decreases. Gas residual saturation conditions in the gas cap region are not expected to affect the maximum lateral plume extent as much as the existent volume of gas. The effect of gas cap composition in CO₂ migration is dominated by pressure changes within the formation which subsequently affects the gas cap compressibility and in consequence the plume maximum lateral extent. For example, contamination of a methane-rich gas cap by injected CO₂ has a strong effect on the plume maximum lateral extent due to compressibility changes. This, in turn, affects regulatory Area of Review, project technical risks, and economics. In another part of the study, a dimensional analysis was performed to identify and assess dominant forces relevant to CO₂ plume distribution in the presence of a gas cap. Dimensionless groups were used to express the relationship between centroid location and the ratio of gravity and viscous forces given by the gravity number. Appropriate assessment of gas cap impact on CO₂ plume distribution and on aquifer pressure build-up is fundamental for developing an accurate economic outlook as well as for taking into account regulatory constraints (including a monitoring plan addressing leakage risk and possible aquifer contamination)
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    Evaluating the influence of seal characteristics and rate of pressure buildup on modeled seal performance and carbon sequestration economics
    (2008-12-20) Kalyanaraman, Nishanth; Fisher, W. L. (William Lawrence), |d 1932-
    This research investigates seal performance for carbon dioxide (CO2) sequestration in brine reservoirs. Numerical codes were adapted from the natural gas (methane) storage industry and modified for CO2 applications to investigate the factors influencing migration rates and magnitudes through a sealing layer resulting from pressure buildup in an underlying injection reservoir. The factors investigated include seal characteristics such as thickness and permeability as well as the characteristics of pressure buildup, such as rate and magnitude. The goal was to understand fundamental processes involved in CO2 migration through a seal and to determine how these factors affect CO2 migration rates and magnitudes through the seal and net volume retained. An expected result from this modeling indicates an approximately linear relationship between maximum pressure buildup and CO2 leakage. Unexpected conclusions include the non-linearity between seal thickness and CO2 leakage indicating that doubling seal thickness does not necessarily halve the leakage volume. Another non linear relationship is observed between seal permeability and CO2 leakage. In addition, it is shown that there is a minimum seal permeability that performs adequately (essentially no leakage) and permeabilities lower than that do not decrease seal risk. The integrated flow model developed is used to calculate the net volumes retained in the formation for different injection scenarios with a fixed injection volume and the results are integrated into the economic assessment of carbon sequestration. The second component of this thesis research addressed the economic implications of various injection scenarios, focusing on the various ways a fixed amount of CO2 could be used. An economic model was built to investigate the factors influencing the net present value of carbon sequestration in EOR and non-EOR projects. The factors investigated include the timing (duration) of different injection rates, CO2 credit received for successful storage, leaked CO2 fraction (output from seal performance model) and economic parameters such as CO2 price, operating and capital expenses and discount rate. The results from this analysis are that: 1) The CO2 leak rate calculated from the flow model is low for the conditions modeled and has negligible impact on the net present value when compared to CO2 credit and the timing of different injection rates; 2) longterm sequestration projects operating at low pressures may never become profitable with low CO2 credit and this provides an incentive to operate at higher injection pressures; 3) most regulators may favor lower injection pressures to avoid risks of leakage. Higher CO2 credits are needed to make these long-term projects attractive; and 4) for CO2 credits over $2.22/ tonne, it would be profitable to continue sequestration after EOR, providing a backstop for any economic risks of standard EOR projects
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    Assessing an offshore carbon storage opportunity at Chandeleur Sound, Louisiana
    (2023-05-04) Li, Yushan, M.S. in Energy and Earth Resources; Hovorka, Susan D. (Susan Davis); Uroza, Carlos; Gil Egui, Ramon
    Carbon Capture and Storage (CCS) is considered a crucial technology for climate change mitigation. Its primary objective is to reduce CO₂ emissions caused by human activities by capturing gas from large point sources or from direct air capture and injecting it into deep geologic formations. This study focuses on the geological characterization and CO₂ storage capacity estimation for an offshore state water site – Chandeleur Sound, Louisiana. Form literature review, the storage window is narrowed to Middle and Upper Miocene. 3-D seismic data was used for fault and horizon picking, stratal slicing and attribute mapping. Three attributes/methods were used in the stratal slices: Sum Negative Amplitude, RMS amplitude, and Spectral Decomposition. The slices give a qualitative overview of the depositional trends and faulting in Chandeleur Sound and concluded that the ideal storage intervals include the Upper Miocene in the southern area, the upper part of Middle Miocene, and a massive channel system near the top of Upper Miocene which is likely to be a deposit from the paleo Tennessee River. Well log correlation was used to identify seven reservoir zones. Detailed reservoir properties were defined for these zones. The thickest net sand interval within the Chandeleur Sound area is found in the center. Static and dynamic storage capacity calculations estimate a total storage capacity of 306 to 2,000 million metric tons. of CO₂, depending on boundary condition. The value of 306 Mt is the most realistic and is used for source-sink matching. Chandeleur Sound is close to Louisiana Chemical Corridor (LCC) and has plenty of point sources for CO₂ supply. The costs associated with carbon capture, transport and storage and were considered. Pipeline is the only transport scenario considered for large volumes that must be transported on land and then into shallow marine settings. CO₂ pipeline regulations include both federal and state level jurisdiction. Pipeline costs estimation using FECM/NETL CO₂ Transport Cost Model and Terrain-based approach concluded that a 20 inches pipeline from the carbon gathering hub to the injection site would have a construction cost from $140 million to $1.16 billion in 2023’s dollars.
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    Estimating across-fault migration rates and their financial implications for CCS with application to offshore Gulf of Mexico
    (2022-05-10) Guirola, Marco Andrés, Jr.; Bump, Alexander P.; Hovorka, Susan D. (Susan Davis); Hennings, Peter H; Hahn, Warren J
    In the Gulf of Mexico, faults usually behave as CO2 flow barriers that aid containment, but sometimes across-fault migration of CO2 is possible. Petroleum fault seal analysis predicts whether a fault seals or transmits hydrocarbons. This suffices to reveal whether accumulations drain over geologic timescales. CCS operates on human timescales. Quantification of the rate of a potential migration is an essential and relatively unexplored component in CCS. Migration rates allow to anticipate costs related to liability and returned carbon credits, which affects the profitability of CCS investments. In this study, I create an algorithm to estimate across-fault migration rates of CO2. I use fault seal analysis plus application of Darcy’s law to the areas on the fault with the highest transmission potential. I then transform the rates to cumulative transmitted masses and perform stochastic simulations to bracket the range of rates according to fault attribute uncertainties. I illustrate the algorithm with a model of a double fault-bounded storage prospect in the northern GoM shelf. I tested the algorithm for 40 years of injection at a rate of 0.7 MtCO2. If the injector is placed 1 km away from the faults, the cumulative transmitted masses of CO2 are between 137.19 and 7,408.93 ktCO2 for open and closed boundary conditions respectively (or between 0.49% and 26.46% of the injected total). It is likely more realistic to assume the, at worst, the reservoir’s boundaries are semi-closed. In this case, simulations output between 372.03 and 570.24 ktCO2 (1.61% average of injected total) of migration with 90% confidence. The results suggest that in similar GoM settings with abundant shales, the fault core permeability and thickness should be favorable for sealing. However, they can exhibit 3 and 1 orders of magnitude of variation respectively and thus should be modeled as uncertainty distributions. I found that pressure and area of highest transmission potential are the critical drivers of migration rate. In application to financial investment scenarios, the net present value of an injection project into the GoM trap varied from $52.32M to $63.02M depending on migration rates. The result indicates that migration rates are key in scoping for financially viable projects.
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    Evaluating, risking, and ranking carbon sequestration buoyant traps with application to nearshore Gulf of Mexico
    (2022-05-16) Laidlaw, Madeleine C.; Bump, Alexander P.; Hovorka, Susan D. (Susan Davis); Peel, Frank J
    It is critical to streamline investment into CCS projects to reduce the concentration of greenhouse gases in the atmosphere and reduce the impacts of climate change. The Gulf of Mexico is a prime location to develop CCS projects due its vast geologic carbon storage potential, proximity to concentrated CO₂ emissions, and coincidence with an experienced hydrocarbon industry that can lend its expertise to this young field. The petroleum industry uses prospect inventories, catalogues of discovery opportunities, to identify potential projects, quantify their associated risks, and rank them to focus on prospects to maximize the potential of high-quality investments (Lottaroli et al 2018). This work improves upon existing prospect inventories considering only buoyant traps in the Miocene section in state and nearshore federal waters of offshore Texas and Louisiana (TexLa Dataset) by incorporating fault seal as a trapping mechanism and including lithological and petrophysical data from a comprehensive 3D geologic model. The result was larger, amalgamated buoyant traps prospects which are more likely to support development projects due to their size and continuity. The usefulness of a prospect inventory is realized when the subsurface and above ground risks associated with each buoyant trap prospect are quantified, allowing prospects to be ranked by suitability for project development. Quantifying risk differentiates prospects, highlights those of greatest promise, and allows developers to make more informed choices about which projects to pursue. Subsurface risk was evaluated by considering structural trap, confining zone, well leak, capacity, and injectivity risk. Above-ground risk was examined by looking at the political and permitting conditions in the region and building a sequestration discounted-cash flow valuation model to quantify each prospect’s economic potential. This work shows that it is possible to risk and rank CCS prospects using commonly available data and quantitative, repeatable workflows that can be applied anywhere in the world. The final useful output of this work is a ranked list of the buoyant trap storage opportunities within the Miocene section of the TexLa region. Broad risk ranking were conducted using Common Risk Segment (CRS) maps. More differentiating risk-weighted values for the prospects were calculated using Expected Monetary Value ($MM).
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    Geochemical evolution of karst vadose water and brush clearing impacts on recharge in central Texas
    (2008-12) Wong, Corinne; Banner, Jay L.
    Groundwater geochemistry is used to investigate flow paths, water residence times, and rock-water interaction processes, which is especially important in central Texas where groundwater flow is unpredictable and difficult to study due to the anisotropic nature of karst terrains. The first part of this study is a multiyear monitoring study that identifies and quantifies the processes controlling vadose drip water evolution in a cave, Natural Bridge Caverns, central Texas. Three different types of drip water are identified. Group 1 drip sites (n=3) are characterized by strong seasonal variations in Mg/Ca and Sr/Ca that are driven by seasonal fluctuations in calcite precipitation related to winter cave ventilation. Group 2 drip sites (n=4) exhibit correlations between drip water composition (Mg/Ca, Sr/Ca, and ⁸⁷Sr/⁸⁶Sr) and measures of water flux (rainfall and drip rate). Mass balance modeling demonstrates rock-water interactions (i.e., dissolution-reprecipitation processes involving carbonate minerals comprising host Cretaceous carbonate rocks) can account for drip water compositions. Group 3 sites (n=2) exhibit limited geochemical, physical or temporal correlations. Group 3 sites likely reflect a combination of Groups 1 and 2 processes, as drip water composition suggests both varying extents of rock-water interaction and calcite precipitation. The results of this study provide insight on the processes controlling the geochemical evolution of vadose karst waters and can be applied toward uncoding the paleoclimate signals recorded in speleothems. More specifically, in areas where cave-air CO₂ fluctuates seasonally, speleothem Mg/Ca and Sr/Ca variations may serve as chemical indicators of annual laminae, and speleothem growth may be biased. The second part of the study uses changes in drip rate and drip water geochemistry to evaluate the affects of brush clearing on recharge. Brush clearing is commonly used to increase stream and spring flow in central Texas even though it is not clear whether or not brush clearing enhances recharge. Drip rate and drip water composition were monitored every four to six weeks from May 2004 to April 2008. Brush clearing above the cave was conducted from April 2007 to July 2007. Drip rate and drip water compositions were compared at nine drip water sites, five of which are directly beneath an area cleared during this study. There were no changes in drip rate, Mg/Ca, Sr/Ca, or ⁸⁷Sr/⁸⁶Sr at drip sites beneath the cleared area that could be attributed to the brush clearing. The lack of change in drip water compositions and drip rates indicate that the brush clearing did not have a discernible impact on recharge to the cave, and suggests brush clearing does not have an impact on vadose recharge.
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    High order stratigraphic framework of intraslope growth faulted subbasins offshore Matagorda Bay, Texas
    (2021-12-09) Franey, John D.; Meckel, Timothy Ashworth
    Carbon capture and storage (CCS) is currently one of the leading atmospheric emission mitigation technologies. To have meaningful impact on the atmosphere CO₂ concentrations, megatons (10⁶) of CO₂ must be removed from the carbon cycle permanently. This requires a subsurface geologic storage sites that are both volumetrically significant and secure over geologic time-scales. The northern Gulf of Mexico (GOM) has the ability to serve as a major location for CCS. Miocene strandplain systems in the GOM are an ideal stratigraphy for such storage due to their proximity to emissions sources, quality sand reservoirs, and depth relative to overpressure. This study focuses on a suite of strike parallel subbasins within the Lower Miocene offshore Matagorda Bay, TX. Each subbasin has potential to serve as a future carbon sequestration site. Accurate mapping of subbasins’ stratigraphy is necessary to understand the variable thickness and associated risk of reservoir-sealing shale intervals, recognizing that injection beneath thicker, more uniformly distributed shales is more favorable. These intervals must be mapped at high resolution (4th order cyclicity) to understand the individual components in assessment and risk analysis. This research generates a novel dip-steered seismic volume which is leveraged to improve seismic attribute calculations and mapping at the 4th order. The dip-steered seismic volume records the seismic dip in the inline and crossline direction of seismic features at the intersection of every inline, crossline, and seismic sample. This volume is used to generate a model of dense, 3D, auto-tracked horizons across each subbasin. The models better connect high resolution, but sparse, well log data and low resolution, but continuous, seismic data. Thickness distributions and shale interval maps generated from the models aid in risk assessment. Based on the resulting shale thicknesses, the suite of subbasins should be further considered as future storage sites
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    Constraining the data and investment needs for obtaining a carbon dioxide injection permit in the United States
    (2021-08-09) Barnhart, Taylor H.; Hovorka, Susan D. (Susan Davis)
    To keep global temperature increases below 2 ̊C, utilization of carbon capture and storage (CCS) must proliferate, but the U.S. has only issued two Underground Injection Control (UIC) Class VI permits for carbon dioxide (CO₂) storage in saline formations. An impediment to CCS development is uncertainty regarding investment requirements for selecting and characterizing a storage site to obtain an injection permit. A Class VI permit application requires adequate site characterization to ensure that no underground sources of drinking water (USDWs) will be negatively impacted by CO₂ storage. Collection of characterization data involves financial expenditures at different project development investment gates. Here these gates are designated as Feasibility, Site(s) Selection, Detailed Characterization, and Permit Preparation. To estimate the potential investments at each gate, a novel approach was developed and applied to 31 case study storage sites in the Southeast Regional CO₂ Utilization and Storage Acceleration Partnership (SECARB-USA) region. This approach included development of a data needs framework, which consists of data required under Class VI regulations, data for multiphase fluid flow modeling, and data for development of a site monitoring program. Two site evaluation rubrics were derived from this data needs framework to assess the urgency and availability of data at a site. The cost of site characterization is a function of the data density (data availability) and data urgency of a site. These rubrics were used to assign scores to the 42 data needs in the data needs framework, and the subsequent data need scores were referenced to a characterization activity cost index to estimate the costs at each investment gate for each site. Results indicate that the total characterization cost across the case study sites are nearly identical unless high cost characterization activities, such as conducting a 3-D seismic survey or drilling, coring, and testing a characterization well, are unnecessary because the data already exist. Existence of these data lowers project risk as early investment gates can be passed with lower investments. Other trends in the dataset reinforce the value of stacked storage sites for reducing costs and existing well penetrations for providing subsurface data
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    Plume migration and pressure evolution analyses for recommendations in offshore CO₂ storage acreage leasing policy
    (2021-05-13) Ulfah, Melianna; Hovorka, Susan D. (Susan Davis)
    This study inputs extensive geological and petrophysical data into a reservoir simulation to model the CO₂ migration, analyze the plume and pressure distribution and evolution, and link the results to policy recommendations. I built a reservoir model, based on 3-D seismic interpretation of Middle Miocene strata, offshore Galveston, Texas and utilized well logs to characterize key intervals. The modeling investigated how far the CO₂ plume would migrate under two scenarios: injecting CO₂ at the base of the salt withdrawal basin (syncline scenario) and injecting CO₂ at the base of the structural closure (base scenario). The simulation shows that by injecting the CO₂ into the syncline, we need more acreage to be leased rather than injecting CO₂ at the base of the structural closure for the same amount of CO₂. The reason why syncline mechanism takes more acreage is because the geological layer around the injection point is more heterogeneous than the base scenario, thus making the CO₂ tends to migrate laterally. On the positive side, such mechanism also limits the vertical migration of CO₂, thus making syncline mechanism much less prone for the CO₂ to escape to the upper geological layers. Moreover, the simulation also shows that with syncline scenario, the times needed for the reservoir to reach its stabilized pressure after the end of injections are faster. Another result of the simulation also shows that adding more wells into the study area would not significantly increase the storage capacity, and each well will suffer injectivity loss even more to maintain the reservoir pressure. Integrating the simulation results and existing policies for offshore CO₂ storage, this study culminates several recommendations for the General Land Office regarding the acreage leasing policies. The main recommendation is to classify of the acreage valuation according to either the heterogeneity degree of the storage geology or the type of the structural closure targeted by the operator. Additionally, it is recommended for the GLO to closely evaluate and if necessary, limit the number of wells and operators for CO₂ storage project operating in one elevated pressure area
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    Screening and assessing the CO₂ storage potential of CO₂-EOR in onshore oil fields in Louisiana
    (2021-07-24) Aluge, Arnold Oseiy; Hovorka, Susan D. (Susan Davis); Nuñez-López, Vanessa
    CO₂ enhanced oil recovery (CO₂-EOR) is a form of carbon storage that has the potential to minimize CO₂ emissions while also increasing energy output from newly recovered oil. Louisiana is the 5th largest emitter of energy-related CO₂ in the United States, with about 200 million metric tonnes of CO₂ emitted annually. Louisiana has over 20,000 oil and gas reservoirs and 287 CO₂ point sources. This study used a screening methodology at the reservoir level to identify appropriate CO₂-EOR candidate reservoirs in Louisiana and their CO₂-EOR reserve estimates. Also, an economic analysis of CO₂-EOR was carried out in this thesis, which included sensitivity and scenario analysis. In Louisiana, this study identified 217 reservoirs across 86 oil fields as potential CO₂-EOR candidates. According to the Louisiana assessment, the 217 candidate reservoirs have a total of 1.4 billion STB of OOIP and a 205 million STB incremental oil potential worth $12.3 billion. The CO₂ storage capacity of these reservoirs is projected to be 100 million metric tons. There are several other suitable candidate reservoirs in Louisiana that were not taken into account in this analysis. When combined with the reservoirs described in this thesis, the incremental oil recovered potential and CO₂ reservoir storage capacity will reach 1.5 billion STB and 2.6 billion metric tons, respectively. In Haynesville, Bayou Segnette, and Paradis, case studies were conducted for suitable CO₂-EOR candidate reservoirs. The sensitivity studies revealed that the net income and economic viability of a CO₂-EOR project are highly dependent on oil price, CO₂ cost, and tax policy. CO₂-EOR would benefit greatly from the high oil price, low CO₂ cost, and low tax policy. Given the current economic situation, the economic analysis indicates that operating successful CO₂-EOR projects would be difficult. However, the study also shows that CO₂-EOR projects can be made economically feasible by combining 1. tax reductions/exemptions in areas such as royalties, income tax, and severance tax. 2. negotiating lower CO₂ prices 3. Increase in tax credit for capturing facilities to lower CO₂ prices for storage parties
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    Characterizing reservoir quality for geologic storage of CO2 : a case study from the Lower Miocene shore zone at Matagorda Bay, Texas
    (2021-05-10) Hull, Harry Lejeune; Meckel, Timothy Ashworth
    The geologic storage of anthropogenic CO₂ through Carbon Capture, Utilization, and Storage (CCUS) is necessary to reduce the emissions produced as a biproduct of fossil fuel combustion. This process of injecting CO₂ into the subsurface is known as carbon sequestration and requires the assessment of geologic reservoirs. Depositional processes and the resulting facies and stratigraphic architectures have great influence over reservoir volumetrics and behavior. The objective of this study is to constrain the depositional controls on storage capacity. A subsurface Lower Miocene 2 strandplain/barrier bar complex of the Texas Gulf Coast at Matagorda bay is interpreted and modeled using well data and 3D seismic. These data reveal the presence of a major shore zone that experienced initial progradation through the late highstand and into the lowstand before later retrogradation. The LM2 is then capped by a thick regional shale. A stratigraphic framework is built that captures these changes in shoreline position at both the systems tract and parasequences level. Sediments were strike fed and wave-dominated processes are apparent. Petrophysical properties of this region including porosity are modeled from with machine learning from log data. Machine learning to predict porosity is carried out using a random forest regression in which porosity is a function of lithology and depth. Finally, a 3D reservoir model is built integrating the stratigraphic, facies, and petrophysical properties. Static storage capacity estimates and storage capacity maps are created from the 3D model. Storage capacity is observed to occur at a strike parallel geometry. This “axis” of highest storage capacity tracts with the position of the shore zone in vertical succession highlighting a dependence on the balance between the generation of accommodation and sediment supply. At a higher resolution storage capacity is observed highest within the foreshore where beach ridges are interpreted from seismic stratal slices. High wave energy processes at this position in the shoreline profile are known to create well sorted and therefore highly porous sandstones. Storage capacity is then a direct function of the high wave energy paleo-depositional processes occurring at the shoreline
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    Geologic heterogeneity controls on CO₂ migration and trapping
    (2020-06-19) Ganesan Krishnamurthy, Prasanna; DiCarlo, David Anthony, 1969-; Meckel, Timothy Ashworth; Lake, Larry W; Bryant, Steven L; Prodanovic, Masa
    In this dissertation, we study the influence of small-scale geologic heterogeneities (mm to dm) on buoyant, vertical migration of CO₂ at intermediate length scales (sub-meter) in two different ways: using numerical simulations in highly resolved geologic models, and by visualizing flow through lab generated bedform fabrics. In the first part of this dissertation, we present a new technique to generate high resolution, 3D geocellular models that capture depositional architectures in a realistic manner. We then use a reduced physics formulation (Invasion Percolation) to simulate the migration of CO₂ through the developed models. Results from these simulations provide insight into how the trapped saturation is a non-linear function of the capillary entry pressure contrast between the primary lithologic features. This dependence suggests that some ability to predict CO₂ storage performance can be achieved from common sedimentological descriptors. In the second half, we develop a unique experimental technique to generate intermediate scale (0.6m x 0.6m) beadpacks that mimic natural sedimentary features in a reproducible manner. We then perform a set of two-phase flow experiments in heterogeneous beadpacks with cross-stratified geometry, where the underlying geometry is kept constant but the grain size contrast is varied, analogous to our simulations. The experiments are conducted at atmospheric conditions using an immiscible fluid pair that mirrors the physical properties of supercritical CO₂ and brine at reservoir conditions. Light transmission is used to visualize the flows in real time and quantify fluid saturations at the millimeter scale. Observations from these experiments help corroborate our simulation results, showing that geometry and grain size variability strongly influence CO₂ flow and trapping behavior in a non-linear fashion. We then conduct similar experiments at different flow rates and demonstrate the persistence of heterogeneity effects even at high flow rates and capillary numbers in such vertical flows. These results help demarcate trapping behavior at near well bore and far field conditions. Together these experiments provide a unique opportunity to visualize complex multiphase flow dynamics in realistic geologic fabrics at the sub-meter scale, and can help bridge understanding between core scale experiments and reservoir scale observations
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    Creating a Quick Screening Model for CO2 Flooding and Storage in Gulf Coast Reservoirs Using Dimensionless Groups
    (2006-08) Wood, Derek James; Lake, Larry W.; Johns, Russell T.
    Concerns over global warming have led to interest in removing C02, from the atmosphere. Sequestration of C02 in oil reservoirs as part of enhanced oil recovery (EOR) projects is one method being considered; therefore, it is necessary to identify the most attractive candidate reservoirs for C02 oil recovery and storage. Models from the literature proved inadequate for the purposes of screening reservoirs for C02 flooding; therefore, it was necessary to create a new model. The first step in creating the model was the scaling of continuous C02 flooding. The five dimensionless groups derived for an immiscible waterflood served as the basis for the scaling. When these proved insufficient, the groups were modified and five new groups, including two pressure groups and three saturation groups, were added to the scaling. These 10 groups - the effective aspect ratio, the dip angle group, the water-oil mobility ratio, the C02-oil mobility ratio, the buoyancy number, the injection pressure group, the producing pressure group, the initial oil saturation, the residual oil saturation to water, and the residual oil saturation to gas - were validated and proved to be the necessary groups to completely scale continuous C02 flooding. Using a combination of Box-Behnken and factorial experimental designs, a total of 322 simulations were run with different values of these groups. The results were used to generate response surface fits for the five output model parameters (four for oil recovery and one for C02 storage). The group values were normalized to assist in reducing the number of coefficients in each fit. The final versions of the screening model equations have only 6-8 coefficients, which indicate the groups that are most important in the response surfaces, but still have an acceptable level of accuracy. Only seven of the ten dimensionless groups proved to be important for screening for C02 flooding. These equations can be used by operators to quickly estimate the oil recovery and C02 storage potential for any given reservoir and are ideal for screening large databases of reservoirs to identify the most attractive C02 flooding candidates.
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    CO₂ trapping mechanisms assessment using numerical and analytical methods
    (2020-01-30) Hosseininoosheri, Pooneh; Lake, Larry W.; Werth, Charles J.
    Carbon capture and storage (CCS) is a proven technique for reducing greenhouse gas emissions and climate change. Although monitoring shows that CO₂ can be safely stored underground, CO₂ leakage is still of concern. Therefore, understanding and forecasting the CO₂ distribution over a geological time is necessary to assess the storage performance and related risks. To understand the CO₂ distribution during or/and after a CCS process, four main trapping mechanisms have been introduced: stratigraphic (structural) trapping, residual trapping, solubility trapping, and mineral trapping. The relative contribution of each mechanism in CO₂ sequestration is expected to change over time as CO₂ migrates and reacts with formation rock and fluids. Although structural trapping is the most active trapping mechanism after CO₂ injection, some of the structurally trapped CO₂ dissolves into water with the rest becoming residual over time. Both the residual and dissolved CO₂ then react with rock and trap some of the CO₂, the process of which is recognized as part of mineral trapping. The relative contribution of different trapping mechanisms depends on different parameters, such as the type of geologic sink (i.e., saline aquifers, hydrocarbon reservoirs), and the properties of the reservoir fluids contained. Additionally, in the case of CO₂-EOR/storage the importance of different trapping mechanisms may change depending on the CO₂ injection strategy (e.g., water alternating gas, WAG; continuous gas injection, CGI; water curtain injection, WCI). In this dissertation, I investigate the CO₂ trapping mechanisms in two CCS processes: CO₂-EOR/storage and CO₂ injection in dipping aquifers. First, I investigate the CO₂ trapping mechanisms during and after a CO₂-EOR process using reservoir simulation. The main purpose is to answer questions associated with the relationship between EOR operational strategies and CO₂ utilization ratios, and to understand the impact of the different CO₂ trapping mechanisms on this relationship. To answer these questions, I integrate three main elements of field assessment: physical field characterization, production and pressure history, and reservoir simulation. I use this method to model and compare two fields that represent two different reservoir settings: Cranfield (representative of the U.S. Gulf Coast sandstone reservoirs) and SACROC (representative of the Permian Basin carbonate reservoirs). CGI is the original operating strategy in Cranfield and WAG is the original operating strategy applied in the SACROC unit. Second, I investigate the impact of relative permeability on the trapping mechanisms in a CO₂-EOR process using fractional flow analysis and reservoir simulation. I use the fractional flow theory for miscible displacement to analytically and graphically analyze the distribution of CO₂ trappings. I use the Cranfield model to show the impact of relative permeability on field predictions. I discuss the relative permeability impact on four different CO₂ injection schemes: continuous gas injection (CGI), water alternating gas injection (WAG), water curtain injection (WCI), and WCI+WAG. Third, I introduce a mathematical model, derived from force balance, to predict CO₂ plume migration in dipping aquifers. This model calculates the down and up-dip extension of CO₂ plume in the absence of trapping mechanisms. The force balance shows that there is a point in the down-dip flow where buoyancy and viscous forces are equal and the plume cannot extend further. However, in the up-dip flow, where the direction of viscous and buoyancy forces are the same, the plume migrates upward for an unlimited time. I validate the mathematical model against numerical simulation results. I introduce an effective relative permeability correlation to capture the competition between water and CO₂. I adjust the permeability of the aquifer to validate the mathematical model against heterogeneous cases. The results show that the heterogeneity-induced error is small if we use the near well-bore average permeability. I also investigate the effect of local capillary trapping on the plume shape. Using numerical simulation, I apply capillary trapping and show how capillary forces prevent the buoyant CO₂ from migrating up-dip.
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    Characterization of the High Island 24L Field for modeling and estimating CO₂ storage capacity in the offshore Texas state waters, Gulf of Mexico
    (2019-07-25) Ruiz, Izaak; Meckel, Timothy Ashworth
    Carbon, Capture, and Storage (CCS) is considered an essential technology that can contribute to reaching the IPCC’s target to limit global average temperature rise to no more than 2.0°C. The fundamental purpose of CCS is to reduce anthropogenic CO₂ emissions by capturing gas from large point sources and injecting it into deep geologic formations. In the offshore Texas State Waters (10.3 miles; 16.6 kilometers), the potential to develop CO₂ storage projects is viable, but the size of storage opportunity at the project level is poorly constrained. This research characterizes the High Island 24L Field, a relatively large historic hydrocarbon field, that has produced mainly natural gas (0.5 Tcf). The primary motivation for this study is to demonstrate that depleted gas fields can serve as volumetrically significant CO₂ storage sites. The stratigraphy of the inner continental shelf in the Gulf of Mexico has been extensively explored for hydrocarbon for over 50 years, and this area is well suited for CCS. Lower Miocene sandstones beneath the regional transgressive Amphistegina B shale have appropriate geologic properties (porosity, thickness, extent) and can be characterized utilizing 3D seismic and well logs in this study. Identifying key stratigraphic surfaces, faults, and mapping structural closure footprints illustrates the field’s geologic structure. The interpreted stratigraphic framework can then be used to model three different lithologic facies and effective porosity to calculate CO₂ storage capacity for both the ~200-ft (60-m) thick HC Sand (most productive gas reservoir) and the overlying thicker 1700 ft (520 m), but non-productive, Storage Interval of Interest. Four different methodologies are utilized to achieve confidence in the CO₂ storage capacity estimates. A storage capacity of 15 – 23 MT is calculated for the HC Sand and 108 – 179 MT for the Storage Interval of Interest by applying interpreted efficiency factors. This study evaluates the accuracy of these storage capacity methodologies to better understand the key geologic factors that influence CO₂ storage in a depleted hydrocarbon field for CCS
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    Geologic characterization and modeling for quantifying CO₂ storage capacity of the High Island 10-L field in Texas state waters, offshore Gulf of Mexico
    (2019-09-12) Ramirez Garcia, Omar; Chuchla, Richard J. (Richard Julian); Meckel, Timothy Ashworth
    Carbon dioxide capture and storage (CCS) is a promising technology for mitigating climate change by reducing CO₂ emissions to the atmosphere and injecting captured industrial emissions into deep geologic formations. Deep subsurface storage in geologic formations is similar to trapping natural hydrocarbons and is one of the key components of CCS technology. The quantification of the available subsurface storage resource is the subject of this research project. This study focuses on site-specific geologic characterization, reservoir modeling, and CO₂ storage resource assessment (capacity) of a depleted oil and gas field located on the inner continental shelf of the Gulf of Mexico, the High Island 10L field. lower Miocene sands in the Fleming Group beneath the regional transgressive Amphistegina B shale have extremely favorable geologic properties (porosity, thickness, extent) and are characterized in this study utilizing 3-D seismic and well logs. Key stratigraphic surfaces between maximum flooding surfaces (MFS-9 to MFS-10) demonstrate how marine regression and transgression impact the stacking pattern of the thick sands and overlying seals, influencing the overall potential for CO₂ storage. One of the main uncertainties when assessing CO₂ storage resources at different scales is to determine the fraction of the pore space within a formation that is practically accessible for storage. The goal of the modeling section of this project is to address the uncertainty related to the static parameters affecting calculations of available pore space by creating facies and porosity geostatistical models based on the spatial variation of the available data. P50 values for CO₂ storage capacity range from 37.56 to 40.39 megatonnes (Mt), showing a narrow distribution of values for different realizations of the geostatistical models. An analysis of the pressure build-up effect on storage capacity was also performed, showing a reduction in capacity. This research further validates the impact of the current carbon tax credit program (45Q), applied directly to the storage resources results for the High Island field 10L using a simple NPV approach based on discounted cash flows. Several scenarios are assessed, where the main variables are the duration of the applicability of the tax credit, number of injection wells, and total storage capacity. Results are measured in terms of the cost of capture required for a project to be economic, given previous assumptions.
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    The Effect of methane and fluid geometry on CO₂ enhanced oil recovery
    (2019-05-08) Prentice, Sarah M.; Hovorka, Susan D. (Susan Davis); Fisher, W. L. (William Lawrence), 1932-
    CO₂ Enhanced Oil Recovery (EOR) is a process that involves injecting large volumes of carbon dioxide as a supercritical fluid into hydrocarbon reservoirs in order to recover hydrocarbons that are not mobilized during primary or secondary production. Some of the injected CO₂ is produced with the produced hydrocarbons and then recycled by reinjection into the reservoir. Most CO₂ floods performed for EOR are miscible, which means the fluids mix to form a homogeneous mixture under a specific set of conditions. For a typical oil field, miscible floods are more efficient in recovering oil than immiscible floods. When recycled CO₂ includes a high percentage of methane, miscibility is significantly reduced. For a typical oil field, miscible floods are more efficient in recovering oil than immiscible floods. Calculations from produced fluid data base shows that at 18 mole percent methane, 28 percent of offshore oil reservoirs became immiscible (Ogbaubau, 2015). The effect was more pronounced in nearshore fields. In this study, I assessed the fluid distribution in a study area to determine if methane production can be avoided by strategic completion of wells to avoid high methane areas. High Island 10L, High Island 24L and ST TR 60S were selected due to availability of structural data. Using seismic, well log interpretation, and production data it was found that, of the wells evaluated, 94 percent had solution gas drive. A number of economic solutions to the problem were postulated; these included a methane separation facility, changes to CO₂ recycling, cutting CO₂ with another gas, and accepting immiscible flood conditions. The following equation was developed to estimate the increased cost for miscible CO₂ enhanced oil recovery: General Additional Costs of CO₂ Enhanced Oil Recovery = (Cost of CO₂ Recycling Plant + Cost of Pipelines + Cost of CO₂ to Offset Methane Immiscibility + Transportation costs + O&M costs + Pipeline Operation Costs) - (Value of Storage Tax Credit), Where: Cost of CO₂ to Offset Methane Immiscibility = (cost of CO₂/ton * tons of CO₂ needed to offset Methane), Cost of Pipelines= (cost of pipeline construction per mile * mumber of miles), Value of Storage Tax Credit = ($35/ton of CO₂ stored Tax Credit*tons of stored CO₂). The equations parameters were then used to create a table showing how the economic solutions might affect the cost of CO₂ enhanced oil recovery.
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    Carbon capture and storage network optimization under uncertainty
    (2018-05) Tutton, Peter Mark; Leibowicz, Benjamin D.; Hovorka, Susan D. (Susan Davis)
    Carbon capture and storage is a method for emissions reductions that can be applied to both the electric sector and industrial sources. Significant uncertainties surround the technologies, policy and extent to which CCS will be deployed in the future. For widespread deployment, future CCS demand should be considered during infrastructure planning. This study presents a novel model that considers spatial information and uncertainty in generating an optimal CCS network. The two-stage stochastic model, utilizes both geographic information systems (GIS) and mixed integer programming (MIP), to generate an optimal near-term hedging strategy. The strategy considers one discrete uncertainty distribution: the future demand for CO₂ storage. A case study in the Texas Gulf Coast demonstrates the value of considering uncertainty of future demand. The optimal solution is selected from a candidate network consisting of twelve sources and five reservoirs that can be linked via a network of pipelines and ship routes. The results demonstrate that optimal hedging strategies lead to transportation cost savings of up to 14% compared to a ‘naive approach’ in which only the expected value is considered. The transportation selection also highlights the benefit of utilizing ship transport in uncertain scenarios due to their ability to be reassigned to a different route or sold.
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    CO₂ storage in deltaic environments of deposition : integration of 3-dimensional modeling, outcrop analysis, and subsurface application
    (2018-05) Beckham, Emily Christine; Meckel, Timothy Ashworth
    Carbon sequestration in geologic reservoirs is a proven method for reducing greenhouse gas emissions. Deltaic deposits are attractive candidates for CO₂ storage projects due to their prominent role as hydrocarbon reservoirs. This research informs subsurface deltaic reservoir characterization and performance for carbon sequestration through integration of geocellular modeling, outcrop analyses, and seismic mapping of prospective offshore CO₂ reservoirs. Results emphasize the importance of recognizing sequence stratigraphic architectures for predicting CO₂ migration. Initially, a model of a deltaic system was generated from a prior laboratory flume deposit to better understand fundamental (but generalized) aspects of reservoir and seal performance. This model was scaled and assigned geologic properties, generating a novel and extremely high-resolution geologic model. Physical architectures represented in the geologic model are consistent with global examples of deltaic reservoirs as well as the facies, stratal stacking pattern, and grain size variability in outcrops studied in this research. Twenty CO₂ injection simulations were run on the geologic model to understand the relationship between reservoir heterogeneity and fluid migration. Baffles affecting migration are identified as the shale layers between sand clinoforms and regressive surfaces in the highstand-lowstand systems tracts. Primary trapping surfaces influencing CO₂ migration are the regressive surfaces in the transgressive systems tract (TST), where migration pathways converge along common surfaces. These sequence stratigraphic observations are then applied to reservoir characterization in 3D seismic data from offshore Gulf of Mexico. The regional, sequence stratigraphic surfaces are well represented in sub-surface data. Hydrocarbon production data indicate fluid accumulation in TST stratigraphy, similar to the geologic modeling results, suggesting some predictability of fluid flow in deltaic settings. The novel integration of datatypes produces enhanced understanding of subsurface fluid flow in deltaic environments.
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    Pre-injection reservoir characterization for CO₂ storage in the inner continental shelf of the Texas Gulf of Mexico
    (2017-05) Sabbagh, Reinaldo Jose; Meckel, Timothy Ashworth
    The injection of CO₂ into the subsurface (carbon capture and storage; CCS) is the most viable approach to significantly reduce industrial emissions of greenhouse gasses to the atmosphere. The inner continental shelf of the northern Gulf of Mexico has incredible potential for CO₂ storage. This study quantitatively evaluates the CO₂ storage capacity of the Lower Miocene brine-filled sandstones in the inner continental shelf of the Texas Gulf of Mexico using 3D seismic and well log data. The first part of this work investigates the relationship between elastic properties and reservoir properties (e.g., porosity, mineralogy, and pore fluid) of the Lower Miocene section using rock physics modeling and simultaneous seismic inversion. The elastic properties are related to porosity, mineralogy and pore fluid using rock physics models. These rock physics transforms are then applied to the seismically derived elastic properties to estimate the porosity and lithology away from the wells. The porosity and lithology distribution derived using this quantitative method can be interpreted to predict the best areas for CO₂ storage in the inner continental shelf of the Texas Gulf of Mexico. The second part of this work studies the effect that CO₂ has on the elastic properties of the Lower Miocene rocks using fluid substitution, amplitude variation with angle (AVA), and statistical classification to determine the ability of the seismic method to successfully monitor CO₂ injected into the subsurface. The velocities and density well logs were modeled with different fluid saturations. To characterize the seismic properties corresponding to these different fluid saturations, the AVA responses and probability density functions were calculated and used for statistical classification. The AVA modeling shows a high sensitivity to CO₂ due to the soft clastic framework of the Lower Miocene sandstones. The statistical classification successfully discriminates between brine and CO₂ saturation using Vp/Vs and P-impedance. These results shows that the Lower Miocene sandstones have the capacity to host CO₂, and that the CO₂ injected in these rocks is likely to be successfully monitored using seismic methods.