GCCC Theses and Dissertations
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Item 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, RamonCarbon 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.Item The behavior of dissolved organic carbon (DOC) at geological sequestration sites(2015-05) Patson, Michael Edwin; Breecker, Dan O.; Larson, Toti Erik; Bennett, Philip CGeologic carbon sequestration has been proposed as a means of mitigating anthropogenic greenhouse gas emissions. At depth, supercritical CO₂ may rise above the surrounding fluid. Detecting leaks from CO₂ storage reservoirs is important to evaluate the effectiveness of carbon sequestration and address public concern for negative environmental impacts. Other attempts have been made to detect leaks, such as changes in pH, pressure and direct observation of CO₂ in the AZMI (Above Zone Monitoring Interval). Each has limitations and here we investigate dissolved organic carbon (DOC) as a potential indicator for fugitive CO₂. This study uses a series of batch experiments to evaluate the interaction between dissolved CO₂ and DOC. The batches consist of homogenized and sieved 250 micron to 425 micron matrix samples of varying mass and type, 2mL of DI water and a headspace of pure carbon dioxide or air. The three different rock samples analyzed are Buffalo River Sediment, illite and Barnett Shale. A pure CO₂ headspace results in lower amount of DOC in solution than an air headspace. All matrix samples demonstrated this effect. The proposed mechanism to describe the observed results is that a lowered pH shifts speciation of weak organic acids and protonated humic substances causing decreased solubility and increasing the adsorption of these compounds. These results suggest that a decrease in DOC concentrations could be used to detect CO₂ leakage and that CO₂ leakage would not deteriorate water quality by releasing DOC.Item 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.Item Carbon dioxide storage in geologically heterogeneous formations(2013-12) Chang, Kyung Won; Hesse, Marc; Nicot, Jean-Philippe, 1958-Geological carbon dioxide (CO₂) storage in deep geological formations can only lead to significant reductions in anthropogenic CO₂ emissions if large amounts of CO₂ can be stored safely. Determining the storage capacity, which is the volume of CO₂ stored safely, is essential to determine the feasibility of geological CO₂ storage. One of the main constraints for the storage capacity is the physical mechanisms of fluid flow in heterogeneous formations, which has not been studied sufficiently. Therefore, I consider two related problems: a) the evolution of injection-induced overpressure that determines the area affected by CO₂ storage and b) the rate of buoyant fluid flow along faults that determines the leakage of CO₂. I use a layered model of a sandstone reservoir embedded in mudrocks to quantify the increase in storage capacity due to dissipation of overpressure into the mudrocks. I use a model of a fault surface with flow barriers to constrain the reduction in the buoyancy-driven leakage flux across the fault. Using the layered model with injection at constant rate, I show that the pressure evolution in the reservoir is controlled by the amount of overpressure dissipated into ambient mudrocks. A main result of this study is that the pressure dissipation in a layered reservoir is controlled by a single dissipation parameter, M, that is identified here for the first time. I also show that lateral pressure propagation in the storage formation follows a power-law governed by M. The quick evaluation of the power-law allows a determination of the uncertainty in the estimate of the storage capacity. To reduce this uncertainty it is important to characterize the petrophysical properties of the mudrocks surrounding the storage reservoir. The uncertainty in mudrock properties due to its extreme heterogeneity or limited data available can cause large variability in these estimates, which emphasizes that careful characterization of mudrock is required for a reliable estimate of the storage capacity. The cessation of the injection operation will reduce overpressure near the injector, but regional scale pressure will continue to diffuse throughout the whole formation. I have been able to show that the maximum radius of the pressure plume in the post-injection period is approximately 3.5 times the radius of the pressure plume at the cessation of injection. Two aquifers can be hydraulically connected by a fault cutting across the intermediate aquitard. If the upper aquifer contains denser fluid, an exchange flow across the fault will develop. The unstable density stratification leads to a fingering pattern with localized zones of upwelling and downwelling along the fault. Due to the small volume of the fault relative to the aquifers, the exchange-flow will quickly approach a quasi steady state. If the permeability of the fault plane is homogeneous, the average number of the quasi-steady plume fingers, (nu), scales with the square root of the Rayleigh number Ra and the exchange flux measured by dimensionless convective flux, the Sherwood number, Sh, is a linear function of Ra. The dispersive flux perpendicular to the flow direction induces the formation of wider fingers and subsequently the less convective flux parallel to the flow direction. In the flow system with larger Ra, even the same increase in transverse dispersivity [alpha]T causes stronger impact of the mechanical dispersion on the vertical exchange flow so that (nu) and Sh reduce more with larger [alpha]T . Both measured characteristics, however, follow the same scaling for the non-dispersive homogeneous case by using a modified Rayleigh number, Ra*, considering the mechanical dispersion. The presence of flow barriers along the fault triggers unsteady exchange flow and subsequently controls the growth of the plume fingers. If the barriers are sufficiently wide to dominate the flow system, they create preferential pathways for exchange flow that determines the distribution of the quasi-steady fingers, and (nu) converges to a constant value. In addition, wider barriers induce substantial lateral spreading and enhance the efficiency of structural trapping, and reduce the exchange rate but still follows a linear relationship function of the effective Rayleigh number, Raeff , defined by the vertical effective permeability. This study is motivated by geological CO₂ storage in brine-saturated aquifer, but the effect of geological heterogeneity is also important in many other geological and engineering applications, in particular the risk assessment of the injection operations or the migration of hydrocarbons in tectonic-driven or hydraulically developed faults in reservoirs. Better understanding of fluid flow in geologically heterogeneous formations will allow more precise estimate of the reservoir capacity as well as more efficient operation of injection or production wells.Item Characterization and prediction of reservoir quality in chlorite-coated sandstones : evidence from the Late Cretaceous Lower Tuscaloosa Formation at Cranfield Field, Mississippi, U.S.A.(2013-05) Kordi, Masoumeh; Fisher, W. L. (William Lawrence), 1932-; Hovorka, Susan D. (Susan Davis)The effectiveness of CO₂ injection in the subsurface for storage and EOR are controlled by reservoir quality variation. This study determines the depositional processes and diagenetic alterations affecting reservoir quality of the Lower Tuscaloosa Formation at Cranfield Field. It also determines the origin, time and processes of the grain-coating chlorite and its impacts on reservoir quality. Moreover, by integrating depositional and diagenetic characteristics and by linking them to sequence stratigraphy, the distribution of reservoir quality, could be predicted within a sequence stratigraphic framework. The studied sandstones are composed of medium to coarse-grained, moderately sorted litharenite to sublitharenite with composition of Q76.1F0.4L23.5. Depositional environment of this formation in the Mississippi Interior Salt Basin is interpreted as incised-valley fluvial fill systems. The cross sections and maps at the field show trend of the sandy intervals within channels with a NW-SE paleocurrent direction. During burial of the sandstones, different digenetic alterations including compaction, dissolution, replacement and cementation by chlorite, quartz, carbonate, kaolinite, titanium oxides, pyrite and iron-oxide modified the porosity and permeability. Among these, formation of chlorite coats plays the most important role in reservoir quality. The well-formed, thick and continuous chlorite coatings in the coarser grain sandstones inhibited formation of quartz overgrowth, resulted in high porosity and permeability after deep burial; whereas the finer grain sandstones with the poorly-formed, thin and discontinuous chlorite coatings have been cemented by quartz. The optimum amount of chlorite to prevent formation of quartz overgrowths is 6% of rock volume. The chlorite coats are composed of two layers including the inner chlorite layer formed by transformation of the Fe-rich clay precursors (odinite) through mixed-layer clays (serpentine-chlorite) during early eodiagenesis and the outer layer formed by direct precipitation from pore waters through dissolution of ferromagnesian rock fragments during late eodiagenesis to early mesodiagenesis. In the context of the reservoir quality prediction within sequence stratigraphic framework, the late LST and early TST are suitable for deposition of chlorite precursor clays, which by progressive burial during diagenesis could be transformed to chlorite, and thus results in preserving original porosity and permeability in deep burial.Item 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 AshworthCarbon, 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 CCSItem 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 AshworthThe 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 shorelineItem Compositional changes of light hydrocarbons during migration through overburden : proxy for assessing potential leakage from Geological Carbon Storage(2017-12) Anderson, Jacob Spencer; Young, Michael H.; Lavier, Luc L; Hesse, Marc A; Breeker, Daniel O; DiCarlo, David ALight hydrocarbon compositions evolve during migration through geologic media, but our understanding of geochemical alteration is limited because of the challenges with analyzing fluids in the sedimentary column. Understanding fluid evolution is timely because of the possibility of upward fluid migration from Geologic Carbon Storage (GCS) operations. The first goal of this research is to identify to what extent hydrocarbons migrate to shallower intervals. Addressing this goal is challenging because microbial hydrocarbon production commonly occurs in the near-surface. Light hydrocarbon compositions are investigated in soil gas above a hydrocarbon system and in offshore sediment above a gas chimney. In both cases, the fluid sources are interpreted as microbial in origin. However, these geochemical datasets are relevant to attributing future light hydrocarbon seeps and anomalies above GCS sites. The second goal is to quantify alteration processes when migration has occurred. I hypothesize that phase changes and sorption are the primary alteration processes. To test this hypothesis, I numerical simulation these processes to compare with field datasets that are interpreted as migration. The models indicate that sorption has the most significant influence on light hydrocarbons, although more lab work is warranted to improve these models. Forward models of CO₂ migration show that phase changes are important in attenuating CO₂ and can be identified with noble gas compositions. This conclusion may be valuable to determining the source of CO₂ anomalies above GCS sites.Item 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 dataItem CO₂ storage in deltaic environments of deposition : integration of 3-dimensional modeling, outcrop analysis, and subsurface application(2018-05) Beckham, Emily Christine; Meckel, Timothy AshworthCarbon 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.Item 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.Item 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.Item Development of a four-phase thermal-chemical reservoir simulator for heavy oil(2014-12) Lashgari, Hamid Reza; Sepehrnoori, Kamy, 1951-Thermal and chemical recovery processes are important EOR methods used often by the oil and gas industry to improve recovery of heavy oil and high viscous oil reservoirs. Knowledge of underlying mechanisms and their modeling in numerical simulation are crucial for a comprehensive study as well as for an evaluation of field treatment. EOS-compositional, thermal, and blackoil reservoir simulators can handle gas (or steam)/oil/water equilibrium for a compressible multiphase flow. Also, a few three-phase chemical flooding reservoir simulators that have been recently developed can model the oil/water/microemulsion equilibrium state. However, an accurate phase behavior and fluid flow formulations are absent in the literature for the thermal chemical processes to capture four-phase equilibrium. On the other hand, numerical simulation of such four-phase model with complex phase behavior in the equilibrium condition between coexisting phases (oil/water/microemulsion/gas or steam) is challenging. Inter-phase mass transfer between coexisting phases and adsorption of components on rock should properly be modeled at the different pressure and temperature to conserve volume balance (e.g. vaporization), mass balance (e.g. condensation), and energy balance (e.g. latent heat). Therefore, efforts to study and understand the performance of these EOR processes using numerical simulation treatments are quite necessary and of utmost importance in the petroleum industry. This research focuses on the development of a robust four-phase reservoir simulator with coupled phase behaviors and modeling of different mechanisms pertaining to thermal and chemical recovery methods. Development and implementation of a four-phase thermal-chemical reservoir simulator is quite important in the study as well as the evaluation of an individual or hybrid EOR methods. In this dissertation, a mathematical formulation of multi (pseudo) component, four-phase fluid flow in porous media is developed for mass conservation equation. Subsequently, a new volume balance equation is obtained for pressure of compressible real mixtures. Hence, the pressure equation is derived by extending a black oil model to a pseudo-compositional model for a wide range of components (water, oil, surfactant, polymer, anion, cation, alcohol, and gas). Mass balance equations are then solved for each component in order to compute volumetric concentrations. In this formulation, we consider interphase mass transfer between oil and gas (steam and water) as well as microemulsion and gas (microemulsion and steam). These formulations are derived at reservoir conditions. These new formulations are a set of coupled, nonlinear partial differential equations. The equations are approximated by finite difference methods implemented in a chemical flooding reservoir simulator (UTCHEM), which was a three-phase slightly compressible simulator, using an implicit pressure and an explicit concentration method. In our flow model, a comprehensive phase behavior is required for considering interphase mass transfer and phase tracking. Therefore, a four-phase behavior model is developed for gas (or steam)/ oil/water /microemulsion coexisting at equilibrium. This model represents coupling of the solution gas or steam table methods with Hand’s rule. Hand’s rule is used to capture the equilibrium between surfactant, oil, and water components as a function of salinity and concentrations for oil/water/microemulsion phases. Therefore, interphase mass transfer between gas/oil or steam/water in the presence of the microemulsion phase and the equilibrium between phases are calculated accurately. In this research, the conservation of energy equation is derived from the first law of thermodynamics based on a few assumptions and simplifications for a four-phase fluid flow model. This energy balance equation considers latent heat effect in solving for temperature due to phase change between water and steam. Accordingly, this equation is linearized and then a sequential implicit scheme is used for calculation of temperature. We also implemented the electrical Joule-heating process, where a heavy oil reservoir is heated in-situ by dissipation of electrical energy to reduce the viscosity of oil. In order to model the electrical Joule-heating in the presence of a four-phase fluid flow, Maxwell classical electromagnetism equations are used in this development. The equations are simplified and assumed for low frequency electric field to obtain the conservation of electrical current equation and the Ohm's law. The conservation of electrical current and the Ohm's law are implemented using a finite difference method in a four-phase chemical flooding reservoir simulator (UTCHEM). The Joule heating rate due to dissipation of electrical energy is calculated and added to the energy equation as a source term. Finally, we applied the developed model for solving different case studies. Our simulation results reveal that our models can accurately and successfully model the hybrid thermal chemical processes in comparison to existing models and simulators.Item Development of a two-phase flow coupled capacitance resistance model(2014-12) Cao, Fei, active 21st century; Lake, Larry W.The Capacitance Resistance Model (CRM) is a reservoir model based on a data-driven approach. It stems from the continuity equation and takes advantage of the usually abundant rate data to achieve a synergy of analytical model and data-driven approach. Minimal information (rates and bottom-hole pressure) is required to inexpensively characterize the reservoir. Important information, such as inter-well connectivity, reservoir compressibility effects, etc., can be easily and readily evaluated. The model also suggests optimal injection schemes in an effort to maximize ultimate oil recovery, and hence can assist real time reservoir analysis to make more informed management decisions. Nevertheless, an important limitation in the current CRM model is that it only treats the reservoir flow as single-phase flow, which does not favor capturing physics when the saturation change is large, such as for an immature water flood. To overcome this limitation, we develop a two-phase flow coupled CRM model that couples the pressure equation (fluid continuity equation) and the saturation equation (oil mass balance). Through this coupling, the model parameters such as the connectivity, the time constant, temporal oil saturation, etc., are estimated using nonlinear multivariate regression to history match historical production data. Incorporating the physics of two-phase displacement brings several advantages and benefits to the CRM model, such as the estimation of total mobility change, more accurate prediction of oil production, broader model application range, and better adaptability to complicated field scenarios. Also, the estimated saturation within the drainage volume of each producer can provide insights with respect to the field remaining oil saturation distribution. Synthetic field case studies are carried out to demonstrate the different capabilities of the coupled CRM model in homogeneous and heterogeneous reservoirs with different geological features. The physical meanings of model parameters are well explained and validated through case studies. The results validate the coupled CRM model and show improved accuracy in model parameters obtained through the history match. The prediction of oil production is also significantly improved compared to the current CRM model. A more reliable oil rate prediction enables further optimization to adjust injection strategies. The coupled CRM model has been shown to be fast and stable. Moreover, sensitivity analyses are conducted to study and understand the impact of the input information (e.g., relative permeability, viscosity) upon the output model parameters (e.g., connectivity, time constants). This analysis also proves that the model parameters from the two-phase coupled model can combine both reservoir compressibility and mobility effects.Item Empirical analysis of fault seal capacity for CO₂ sequestration, Lower Miocene, Texas Gulf Coast(2012-05) Nicholson, Andrew Joseph; Meckel, Timothy Ashworth; Tinker, Scott W. (Scott Wheeler); Trevino, Ramon H.; Steel, Ronald J.The Gulf Coast of Texas has been proposed as a high capacity storage region for geologic sequestration of anthropogenic CO₂. The Miocene section within the Texas State Waters is an attractive offshore alternative to onshore sequestration. However, the stratigraphic targets of interest highlight a need to utilize fault-bounded structural traps. Regional capacity estimates in this area have previously focused on simple volumetric estimations or more sophisticated fill-to-spill scenarios with faults acting as no-flow boundaries. Capacity estimations that ignore the static and dynamic sealing capacities of faults may therefore be inaccurate. A comprehensive fault seal analysis workflow for CO₂-brine membrane fault seal potential has been developed for geologic site selection in the Miocene section of the Texas State Waters. To reduce uncertainty of fault performance, a fault seal calibration has been performed on 6 Miocene natural gas traps in the Texas State Waters in order to constrain the capillary entry pressures of the modeled fault gouge. Results indicate that modeled membrane fault seal capacity for the Lower Miocene section agrees with published global fault seal databases. Faults can therefore serve as effective seals, as suggested by natural hydrocarbon accumulations. However, fault seal capacity is generally an order of magnitude lower than top seal capacity in the same stratigraphic setting, with implications for storage projects. For a specific non-hydrocarbon producing site studied for sequestration (San Luis Pass salt dome setting) with moderately dipping (16°) traps (i.e. high potential column height), membrane fault seal modeling is shown to decrease fault-bound trap area, and therefore storage capacity volume, compared with fill-to-spill modeling. However, using the developed fault seal workflow at other potential storage sites will predict the degree to which storage capacity may approach fill-to-spill capacity, depending primarily on the geology of the fault (shale gouge ratio – SGR) and the structural relief of the trap.Item 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 JIn 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.Item 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 projectsItem 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 JIt 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).Item Experimental analysis and modeling of perfluorocarbon transport in the vadose zone : implications for monitoring CO₂ leakage at CCS sites(2013-05) Gawey, Marlo Rose; Breecker, Dan O.; Romanak, Katherine Duncker; Larson, Toti ErikPerfluorocarbon tracers (PFTs) are commonly proposed tracers for use in carbon capture and sequestration (CCS) leak detection and vadose zone monitoring programs. Tracers are co-injected with supercritical CO₂ and monitored in the vadose zone to identify leakage and calculate leakage rates. These calculations assume PFTs exhibit “ideal” tracer behavior (i.e. do not sorb onto or react with porous media, partition into liquid phases or undergo decay). This assumption has been brought into question by lab and field evaluations showing PFT partitioning into soil contaminants and sorbing onto clay. The objective of this study is to identify substrates in which PFTs behave conservatively and quantify non-conservative behavior. PFT breakthrough curves are compared to those of a second, conservative tracer, sulfur hexafluoride (SF₆). Breakthrough curves are generated in 1D flow-through columns packed with 5 different substrates: silica beads, quartz sand, illite, organic-rich soil, and organic-poor soil. Constant flow rate of carrier gas, N₂, is maintained. A known mass of tracer is injected at the head of the columns and the effluent analyzed at regular intervals for tracers at picogram levels by gas chromatography. PFT is expected to behave conservatively with respect to SF₆ in silica beads or quartz sand and non-conservatively in columns with clay or organics. However, results demonstrate PFT retardation with respect to SF₆ in all media (retardation factor is 1.1 in silica beads and quartz sand, 2.5 in organic-rich soil, >20 in organic-poor soil, and >100 in illite). Retardation is most likely due to sorption onto clays and soil organic matter or condensation to the liquid phase. Sorption onto clays appears to be the most significant factor. Experimental data are consistent with an analytical advection/diffusion model. These results show that PFT retardation in the vadose zone has not been adequately considered for interpretation of PFT data for CCS monitoring. These results are preliminary and do not take into account more realistic vadose zone conditions such as the presence of water, in which PFTs are insoluble. Increased moisture content will likely decrease sorption onto porous media and retardation in the vadose zone may be less than determined in these experiments.Item Fault seal and containment failure analysis of a Lower Miocene structure in the San Luis Pass area, offshore Galveston Island, Texas inner shelf(2016-05) Osmond, Johnathon Lee; Meckel, Timothy Ashworth; Gulick, Sean; Marrett, Randall; Eichhubl, PeterFaults that displace siliciclastic reservoirs have been observed to either seal hydrocarbon accumulations in structural traps or serve as conduits for buoyant fluid migration. While many faults located along the Texas Inner Shelf in the Gulf of Mexico do provide adequate lateral seals for the Lower Miocene petroleum system, oil and gas operators targeting the large antiformal structure roughly 7 mi offshore from San Luis Pass have been highly unsuccessful in discovering commercial amounts of methane gas. Images interpreted from 12 mi2 of high-resolution 3-D seismic reflection data (HR3D) has revealed an apparent gas chimney feature directly above the target structure that previously acquired lower-resolution conventional 3-D data failed to identify. Furthermore, the available seismic data show that the 55,000 foot-long normal growth fault displacing the San Luis Pass structure (Fault A) has propagated into the shallow Late Pleistocene (~140 ka) and younger sediment, suggesting recent movement of the hanging wall block has occurred. These three observations call into questions the ability for Fault A to properly seal and contain hydrocarbon accumulations, assuming the structure was sufficiently charged with methane, similarly to the surrounding Lower Miocene structures that have produced. An analysis of fault seal and potential containment failure mechanisms affecting the San Luis Pass structure is conducted here in order to address how hydrocarbons may have escaped into the shallow overburden sediments. 3-D geologic modeling of the Lower Miocene 2 (LM2) reservoir interval and Amph. B Shale top seal against Fault A yields fill-to-spill closure capacities of approximately 686 ft and 992 ft for the footwall and hanging wall closures, respectively. Fault seal membrane limited methane column height estimations are 300 ft and 325 ft from footwall to hanging wall, and were obtained by way of empirically calibrated equations that attempt to account for capillary entry properties of a fault through the estimation of its clay mineral content using the Shale Gouge Ratio (clay volume/fault throw). Although capacity estimations appear to be geologically reasonable in this region, they fail to explain the lack of hydrocarbons in the system, so four potential across-fault migration and leakage scenarios are considered for the purpose of determining pathways from the reservoir interval to the shallow subsurface. Areas where sandstone on sandstone juxtapositions generally pose the greatest risk of across-fault leakage, and 23 individual Lower Miocene 2 and Middle Miocene (MM) sandstone units juxtaposed against Fault A are evaluated. While the ability of Fault A to seal hydrocarbons may be feasible in static conditions, additional mechanisms evaluated using the available data include: top seal membrane leakage, top seal mechanical failure and fault reactivation mechanisms. Top seal thickness ranges between 500 ft and 1,000 ft in the study area, and analogous Lower Miocene mudstones are shown to retain methane columns of about 936 ft. Data limitations significantly reduce the ability to thoroughly investigate top seal mechanical failure and fault reactivation at this time, however, apparent vertical displacement measurements from overlapping seismic datasets suggest that movement along Fault A continued since it originally formed, and that two pulses of increased throw rate may have occurred in Early Miocene, and the Pleistocene. The apparent Pleistocene throw rates range from 0.010 mm/year to 0.125 mm/year, and are significant because the Early Miocene pulse occurred before the formation of the Amph. B top seal. Thus, it is interpreted that fault reactivation may represent the primary containment failure mechanism for the San Luis Pass structure, and that the increased apparent throw rate in the Pleistocene may symbolize a period of hydrocarbon leakage from the LM2 reservoir interval.
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