Browsing by Subject "CCS"
Now showing 1 - 7 of 7
Results Per Page
Sort Options
Item Analysis of Field Development Strategies of CO2 EOR/Capture Projects Using a Reservoir Simulation Economic Model(2013-05-03) Saint-Felix, MartinA model for the evaluation of CO2-EOR projects has been developed. This model includes both reservoir simulation to handle reservoir properties, fluid flow and injection and production schedules, and a numerical economic model that generates a monthly cash flow stream from the outputs of the reservoir model. This model is general enough to be used with any project and provide a solid common basis to all of them. This model was used to evaluate CO2-EOR injection and production strategies and develop an optimization workflow. Producer constraints (maximum oil and gas production rates) should be optimized first to generate a reference case. Further improvements can then be obtained by optimizing the injection starting date and the injection plateau rate. Investigation of sensitivity of CO2-EOR to the presence of an aquifer showed that CO2 injection can limit water influx in the reservoir and is beneficial to recovery, even with a strong water drive. The influence of some key parameters was evaluated: the producer should be completed in the top part of the reservoir, while the injector should be completed over the entire thickness; it is recommended but not mandatory that the injection should start as early as possible to allow for lower water cut limit. Finally, the sensitivity of the economics of the projects to some key parameters was evaluated. The most influent parameter is by far the oil price, but other parameters such as the CO2 source to field distance, the pipeline cost scenario, the CO2 source type or the CO2 market price have roughly the same influence. It is therefore possible to offset an increase of one of them by reducing another.Item Carbon capture and storage potential contribution to mitigate climate change(2009-12) Baca, Angel Mario; Bickel, J. Eric; Duncan, Ian J.; Gutierrez, Genaro J.Carbon Capture and Storage Potential Contribution to Mitigate Climate Change By Angel Mario Baca, M.A. The University of Texas at Austin, 2009 Supervisor: Dr. Eric Bickel This thesis evaluates the potential of the Carbon Capture and Storage technologies to mitigate climate change. This work emerged from the current debate regarding when CCS technologies are going to be ready in a commercial-scale, or whether they are going to be economically viable. Geologically, the world contains enough room for storing CO2 emissions, but it is still unsolved if leakage can be controlled and monitored. This research focuses on the development of an economic model to estimate the value of CCS.. This model uses equations from the DICE (Dynamic Integrated model on Climate and the Economy). Then, it estimates what change in temperature could occur, and computes the present value of damages to the economy. Moreover, emissions are simulated using the 40 scenario emissions from the Intergovernmental Panel on Climate Change. As the main conclusion of this model, CCS has to be deployed in almost in the entire number of fossil fuel plants around the world and has to be done in the next 30 years to see CCS having an impact, otherwise it would be relatively small and not worth it. Moreover, CCS technologies are part of the components to reduce climate change, but not the main one. It is required that governments, companies, and institution focus their efforts in working collaboratively towards the enforcement of new policies and development of more technologies.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 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 Petrophysical modeling and simulatin study of geological CO₂ sequestration(2014-05) Kong, Xianhui; Delshad, Mojdeh; Wheeler, Mary F. (Mary Fanett)Global warming and greenhouse gas (GHG) emissions have recently become the significant focus of engineering research. The geological sequestration of greenhouse gases such as carbon dioxide (CO₂) is one approach that has been proposed to reduce the greenhouse gas emissions and slow down global warming. Geological sequestration involves the injection of produced CO₂ into subsurface formations and trapping the gas through many geological mechanisms, such as structural trapping, capillary trapping, dissolution, and mineralization. While some progress in our understanding of fluid flow in porous media has been made, many petrophysical phenomena, such as multi-phase flow, capillarity, geochemical reactions, geomechanical effect, etc., that occur during geological CO₂ sequestration remain inadequately studied and pose a challenge for continued study. It is critical to continue to research on these important issues. Numerical simulators are essential tools to develop a better understanding of the geologic characteristics of brine reservoirs and to build support for future CO₂ storage projects. Modeling CO₂ injection requires the implementation of multiphase flow model and an Equation of State (EOS) module to compute the dissolution of CO₂ in brine and vice versa. In this study, we used the Integrated Parallel Accurate Reservoir Simulator (IPARS) developed at the Center for Subsurface Modeling at The University of Texas at Austin to model the injection process and storage of CO₂ in saline aquifers. We developed and implemented new petrophysical models in IPARS, and applied these models to study the process of CO₂ sequestration. The research presented in this dissertation is divided into three parts. The first part of the dissertation discusses petrophysical and computational models for the mechanical, geological, petrophysical phenomena occurring during CO₂ injection and sequestration. The effectiveness of CO₂ storage in saline aquifers is governed by the interplay of capillary, viscous, and buoyancy forces. Recent experimental data reveals the impact of pressure, temperature, and salinity on interfacial tension (IFT) between CO₂ and brine. The dependence of CO₂-brine relative permeability and capillary pressure on IFT is also clearly evident in published experimental results. Improved understanding of the mechanisms that control the migration and trapping of CO₂ in the subsurface is crucial to design future storage projects for long-term, safe containment. We have developed numerical models for CO₂ trapping and migration in aquifers, including a compositional flow model, a relative permeability model, a capillary model, an interfacial tension model, and others. The heterogeneities in porosity and permeability are also coupled to the petrophysical models. We have developed and implemented a general relative permeability model that combines the effects of pressure gradient, buoyancy, and capillary pressure in a compositional and parallel simulator. The significance of IFT variations on CO₂ migration and trapping is assessed. The variation of residual saturation is modeled based on interfacial tension and trapping number, and a hysteretic trapping model is also presented. The second part of this dissertation is a model validation and sensitivity study using coreflood simulation data derived from laboratory study. The motivation of this study is to gain confidence in the results of the numerical simulator by validating the models and the numerical accuracies using laboratory and field pilot scale results. Published steady state, core-scale CO₂/brine displacement results were selected as a reference basis for our numerical study. High-resolution compositional simulations of brine displacement with supercritical CO₂ are presented using IPARS. A three-dimensional (3D) numerical model of the Berea sandstone core was constructed using heterogeneous permeability and porosity distributions based on geostatistical data. The measured capillary pressure curve was scaled using the Leverett J-function to include local heterogeneity in the sub-core scale. Simulation results indicate that accurate representation of capillary pressure at sub-core scales is critical. Water drying and the shift in relative permeability had a significant impact on the final CO₂ distribution along the core. This study provided insights into the role of heterogeneity in the final CO₂ distribution, where a slight variation in porosity gives rise to a large variation in the CO₂ saturation distribution. The third part of this study is a simulation study using IPARS for Cranfield pilot CO₂ sequestration field test, conducted by the Bureau of Economic Geology (BEG) at The University of Texas at Austin. In this CO₂ sequestration project, a total of approximately 2.5 million tons supercritical CO₂ was injected into a deep saline aquifer about ~10000 ft deep over 2 years, beginning December 1st 2009. In this chapter, we use the simulation capabilities of IPARS to numerically model the CO₂ injection process in Cranfield. We conducted a corresponding history-matching study and got good agreement with field observation. Extensive sensitivity studies were also conducted for CO₂ trapping, fluid phase behavior, relative permeability, wettability, gravity and buoyancy, and capillary effects on sequestration. Simulation results are consistent with the observed CO₂ breakthrough time at the first observation well. Numerical results are also consistent with bottomhole injection flowing pressure for the first 350 days before the rate increase. The abnormal pressure response with rate increase on day 350 indicates possible geomechanical issues, which can be represented in simulation using an induced fracture near the injection well. The recorded injection well bottomhole pressure data were successfully matched after modeling the fracture in the simulation model. Results also illustrate the importance of using accurate trapping models to predict CO₂ immobilization behavior. The impact of CO₂/brine relative permeability curves and trapping model on bottom-hole injection pressure is also demonstrated.Item Placement and performance of pH-triggered polyacrylic acid in cement fractures(2014-05) Patterson, James William; Bryant, Steven L.A primary concern in the geologic storage of anthropogenic carbon dioxide is the leakage of buoyant CO₂ plumes into shallower formations, aquifers, or the surface. Man-made wells drilled through these formations present a potential leakage pathway for this CO₂ as the cement binding the well to the earth develops fractures or debonded microannuli form over time. Typically, wells with poor cementing or suspected leaks are subject to a cement-squeeze, in which new cement is injected to eliminate the leakage pathway. However, small fractures or leakage pathways are often difficult for oilfield cement to repair, as the cement dispersion is potentially screened out from dispersing fluid and cannot enter the fracture. Therefore a low-viscosity sealant is desired that can enter these leakage pathways easily and provide a robust seal. A class of poly(acrylic acid) polymers known commercially as Carbopol® are pH-sensitive microgels and swell/thicken upon neutralization with alkali cement components. These polymer dispersions are tested for ease of placement into cement fractures and subsequent development of resistance to displacement. Laboratory experiments involved injecting various unswollen polymer microgel dispersion into constructed cement fractures while measuring injection pressure and the pH of the polymer effluent to quantify the chemical reactions taking place and the induced viscosity changes. Fractures were constructed in order to allow for visual inspection of the polymer microgel swelling during and after injection, qualitatively useful in determining the polymer’s efficiency at blocking cement fractures. It was determined that polymer microgels undergo syneresis in the presence of calcium cations that are dissolved from minerals present in cement. The syneresis causes the polymer to collapse onto the cement fracture face and expelled water is left to fill the rest of the fracture, providing little to no resistance to subsequent flow. However, the syneresed polymer does show some potential in blocking or partially blocking small aperture fractures and is not entirely detrimental to fracture blockage in small amounts. An acid pre-flush prior to polymer injection has been seen to favorably reduce the amount of calcium and therefore extent of syneresis, allowing swollen polymer microgels to remain intact and block fluid flow.Item A value of information analysis of permeability data in a carbon, capture and storage project(2012-05) Puerta Ortega, Carlos Andres; Bickel, J. Eric; Hovorka, Susan; Rai, VarunCarbon dioxide capture and storage (CCS) is considered one of the key technologies for reducing atmospheric emissions of CO₂ from human activities (IPCC, 2005). The scale of potential deployment of CCS is enormous spanning manufacturing, power generation and hydrocarbon extraction worldwide. Uncertainty, cost-benefit challenges, market barriers and failures, and promotion and regulation of infrastructure are the main obstacles for deploying CCS technology in a broad scale. In a CCS project, it is the operator’s responsibility to guarantee the CO₂ containment while complying with environmental regulations and CO₂ contractual requirements with the source emitter. Acquiring new information (e.g. seismic, logs, production data, etc.) about a particular field can reduce the uncertainty about the reservoir properties and can (but not necessarily) influence the decisions affecting the deployment of a CCS project. The main objective of this study is to provide a decision-analysis framework to quantify the Value of Information (VOI) in a CCS project that faces uncertainties about permeability values in the reservoir. This uncertainty translates into risks of CO₂ migration out of the containment zone (or lease zone), non-compliance with contractual requirements on CO₂ storage capacity, and leakage of CO₂ to sources of Underground Source of Drinking Water (USDW). The field under analysis has been idealized based on a real project located in Texas. Subsurface modeling of the upper Frio Formation (injection zone) was conducted using well logs, field-specific GIS data, and other relevant published literature. The idealized model was run for different scenarios with different permeability distributions. The VOI was quantified by defining prior scenarios based on the current knowledge of a reservoir, contractual requirements, and regulatory constraints. The project operator has the option to obtain more reliable estimates of permeability, which will help to reduce the uncertainty of the CO₂ behavior and storage capacity of the formation. The accuracy of the information gathering activities is then applied to the prior probabilities (Bayesian inference) to infer the value of such data.