Thesis (M.S.)--Auburn University, 2008. / Abstract. Vita. Includes bibliographical references (p. 95-97).

Implementing geological carbon sequestration at a scale large enough to mitigate emissions will involve the injection of supercritical CO₂ into deep saline aquifers. The principal technical risks associated with such injection are that (i) buoyant CO₂ will migrate out of the storage formation; (ii) pressure elevation during injection will limit storage rates and/or fracture the storage formation; and (iii) groundwater resources will be contaminated, directly or indirectly, by brine displaced from the storage formation. An alternative to injecting CO₂ as a buoyant phase is to dissolve it into brine extracted from the storage formation, then inject the CO₂-saturated brine into the storage formation. This "surface dissolution" strategy completely eliminates the risk of buoyant migration of stored CO₂. It greatly mitigates the extent of pressure elevation during injection. It nearly eliminates the displacement of brine. To gain these benefits, however, it is essential to determine the costs of this method of risk reduction. This work provides a framework for optimization of the process, and hence for cost minimization. Several investigations have tabulated the storage capacity for CO₂ in regions around the world, and it is widely accepted that sufficient pore volume exists in deep subsurface formations to permit large-scale sequestration of anthropogenic CO₂. Given the urgency of implementing geologic sequestration and other emissions-mitigating technologies (storage rates of order 1 Gt C per year are needed within a few decades), the time required to fill a target formation with CO₂ is just as important as the pore volume of that formation. To account for both these practical constraints we describe in this work a time-weighted storage capacity. This modified capacity integrates over time the maximum injection rate into a formation. The injection rate is a nonlinear function of time, formation properties and boundary conditions. The boundary conditions include the maximum allowable injection pressure and the nature of the storage formation (closed, infinite-acting, constant far-field pressure, etc.) The time-weighted storage capacity approaches the volumetric capacity as time increases. For short time intervals, however, the time-weighted storage capacity may be much less than the volumetric capacity. This work describes a method to compute time-weighted storage capacity for a database of more than 1200 North American oil reservoirs. Because all of these reservoirs have been commercially developed, their formation properties can be regarded as representative of aquifers that would be attractive targets for CO₂ storage. We take the product of permeability and thickness as a measure of injectivity for a reservoir, and the product of average areal extent, net thickness and porosity as a measure of pore volume available for storage. We find that injectivity is not distributed uniformly with volume: the set of reservoirs with better than average injectivity comprises only 10% of the total volumetric storage capacity. Consequently, time weighted capacity on time scale of a few decades is 10% to 20% of the nominal volumetric capacity. The non-uniform distribution of injectivity and pore volume in the database coupled with multiphase flow effects yields a wide distribution of “filling times”, i.e. the time required to place CO₂ up to the boundaries of the formation. We define two limiting strategies based on fill times of the storage structures in the database and use them to calculate resource usage for a target storage rate. Since fill times are directly proportional to injectivity, smallest fill time corresponds to best injectivity and largest fill time corresponds to smallest injectivity. If best injectivity structures are used first, then the rate at which new structures would be needed is greater than if worst injectivity structures are used first. A target overall storage rate could be maintained for longer period of time when worst injectivity structures are used first. Because of the kh vs PV correlation, most of the pore volume remains unused when no extraction wells are used. Extraction wells require disposal of produced brine, which is a significant challenge, or beneficial use of the brine. An example of the latter is the surface dissolution process described in this thesis, which would enable use of a much greater fraction of the untouched pore volume. / text

Owing to the excess of carbon dioxide emissions in the atmosphere, a transition to a neutral carbon economy is needed. In this framework, Carbon Capture and Storage (CCS), and Carbon Capture Utilization and Storage (CCUS) become essential areas of development. Sequestering CO2 into different geological media such as deep saline aquifers and hydrocarbon reservoirs reduces the net anthropogenic gas emissions. In 2020, the global CO2 emissions corresponded to 31.5 gigatons. In the case of Saudi Arabia, the Riyadh province emitted 45.8 megatons. This study aims to evaluate for the first time the CO2 storage potential of the Unayzah Formation in Saudi Arabia, identify the primary trapping mechanisms, and capture the effects of the highly heterogeneous reservoir. CO2 injection in geological media is challenging because of the complexity of the geological properties and the CO2 phase behavior at super-critical conditions. In the present evaluation, we constructed a geological model only with public domain data. Similarly, we obtained different scenarios of the model on account of the uncertainty in the geological parameters. Later on, we selected a base model representing a conservative scenario to perform high-resolution simulations to determine the dominant mechanisms influencing the storage efficiency. In the main analysis, we simulated continuous injection of CO2 for forty years followed by twenty years of monitoring. We tested the injectivity of the reservoir showing it is possible to inject 1 and 2 megatons in vertical and horizontal wells, respectively. Likewise, lower injection rates improved solubility and residual trapping. Residual trapping is dominant, and it could reach fifty percent, while solubility could reach up to fifteen percent of the total CO2 injected. Along with these scenarios, we performed an Uncertainty Analysis based on porosity and permeability multipliers, salinity, and hysteresis effect. Finally, we demonstrated the effectiveness of the seal, and the structural and stratigraphic trapping. Until the development of the current analysis, there is no evidence of public domain studies assessing the storage potential into saline aquifers in Saudi Arabia. This contribution is essential for developing CCUS and promoting a circular carbon economy in line with the Vision of the Kingdom for the future.

Although deep saline aquifers are found in all sedimentary basins and provide very large storage capacities, a little is known about them because they are rarely a target for the exploration. Furthermore, nearly all the experiments and simulations made for CO2 sequestration in deep saline aquifers are related to the sandstone formations. The aim of this study is to create a predictive model to estimate the CO2 storage capacity of the deep saline carbonate aquifers since a little is known about them. To create a predictive model, the variables which affect the CO2 storage capacity and their ranges are determined from published literature data. They are rock properties (porosity, permeability, vertical to horizontal permeability ratio), fluid properties (irreducible water saturation, gas permeability end point, Corey water and gas coefficients), reaction properties (forward and backward reaction rates) and reservoir properties (depth, pressure gradient, temperature gradient, formation dip angle, salinity), diffusion coefficient and Kozeny-Carman Coefficient. Other parameters such as pore volume compressibility and density of brine are calculated from correlations found in literature. To cover all possibilities, Latin Hypercube Space Filling Design is used to construct 100 simulation cases and CMG STARS is used for simulation runs. By using least squares method, a linear correlation is found to calculate CO2 storage capacity of the deep saline carbonate aquifers with a correlation coefficient 0.81 by using variables found from literature and simulation results. Numerical dispersion effects have been considered by increasing the grid dimensions. It has been found that correlation coefficient decreased to 0.77 when the grid size was increased from 250 ft to 750 ft. The sensitivity analysis shows that the most important parameter that affects CO2 storage capacity is depth since the pressure difference between formation pressure and fracture pressure increases with depth. Also, CO2 storage mechanisms are investigated at the end of 300 years of simulation. Most of the gas (up to 90%) injected into formation dissolves into the formation water and negligible amount of CO2 reacts with carbonate. This result is consistent with sensitivity analysis results since the variables affecting the solubility of CO2 in brine have greater affect on storage capacity of aquifers. Dimensionless linear and nonlinear predictive models are constructed to estimate the CO2 storage capacity of all deep saline carbonate aquifers and it is found that the best dimensionless predictive model is linear one independent of bulk volume of the aquifer.

Concerns about elevated atmospheric carbon dioxide (CO 2 ) and the effect on global climate have created proposals for the reduction of carbon emissions from large stationary sources, such as power plants. Carbon dioxide capture and sequestration (CCS) in deep geologic units is being considered by Florida electric-utilities. Carbon dioxide-enhanced oil recovery (CO 2 -EOR) is a form of CCS that could offset some of the costs associated with geologic sequestration. Two potential reservoirs for geologic sequestration were evaluated in south-central and southern Florida: the Paleocene Cedar Keys Formation/Upper Cretaceous Lawson Formation (CKLIZ) and the Lower Cretaceous Sunniland Formation along the Sunniland Trend (Trend). The Trend is a slightly arcuate band in southwest Florida that is about 233 kilometers long and 32 kilometers wide, and contains oil plays within the Sunniland Formation at depths starting around 3,414 meters below land surface, which are confined to mound-like structures made of coarse fossil fragments, mostly rudistids. The Trend commercial oil fields of the South Florida Basin have an average porosity of 16% within the oil-producing Sunniland Formation, and collectively have an estimated storage capacity of around 26 million tons of CO 2 . The Sunniland Formation throughout the entire Trend has an average porosity of 14% and an estimated storage capacity of about 1.2 billion tons of CO 2 (BtCO2 ). The CKLIZ has an average porosity of 23% and an estimated storage capacity of approximately 79 BtCO 2 . Porous intervals within the CKLIZ and Sunniland Formation are laterally homogeneous, and low-permeability layers throughout the units provide significant vertical heterogeneity. The CKLIZ and Sunniland Formation are considered potentially suitable for CCS operations because of their geographic locations, appropriate depths, high porosities, estimated storage capacities, and potentiallyeffective seals. The Trend oil fields are suitable for CO 2 -EOR in the Sunniland Formation due to appropriate injected-CO 2 density, uniform intergranular porosity, suitable API density of formation-oil, sufficient production zones, and adequate remaining oil-in-place following secondary recovery. In addition to these in-depth investigations of the CKLIZ and Sunniland Formation, a more-cursory assessment of deep geologic units throughout the state of Florida, which includes rocks of Paleocene and Upper Cretaceous age through to rocks of Ordovician age, shows additional units in Florida that may be suitable for CO 2 -EOR and CCS operations. Furthermore, this study shows that deep geologic units throughout Florida potentially have the capacity to sequester billions of tons of CO 2 for hundreds of fossil-fuel-fired power plants. Geologic sequestration has not yet been conducted in Florida, and its implementation could prove useful to Florida utility companies, as well as to other energy-utilities in the southeastern United States.

Aquifer storage and recovery (ASR) is a particular scheme of artificial recharge of groundwater by injecting fresh water into aquifers and subsequently recovering the stored water during times of peak demand or extended drought. In the era of combating climate change, ASR, as an effective means for water reuse and sustainable management of water resources in concert with the natural environment, represents a huge opportunity for climate change adaptation to mitigate water availability stress.The success of an ASR scheme is quantified by the recovery efficiency (RE), defined as the volume of stored water that can be recovered for supply purposes divided by the total volume injected. It is not uncommon that RE may be significantly lower than 100% because of the water quality changes as a consequence of the mixing between the injected water and native groundwater and the interaction between injected water and soil. Thus, the key of a successful ASR scheme is (1) to select appropriate aquifers and (2) to design optimal operational processes to build up a bubble of injected water with minimized negative impact from such mixing and interaction. To achieve this, this thesis develops an integrated knowledge base with sound interdisciplinary science and understanding of the mixing processes under operational ASR management in aquifers with various hydrogeological conditions. Analytical and numerical modeling are conducted to improve the scientific understanding of mixing processes involved in ASR schemes and to provide specific technical guidance for improving ASR efficiency under complex hydrogeological conditions. (1) An efficient approach is developed to analytically evaluate solute transport in a horizontal radial flow field with a multistep pumping and examine the ASR performance in homogeneous, isotropic aquifer with advective and dispersive transport processes. (2) Numerical and analytical studies are conducted to investigate the efficiency of an ASR system in dual-domain aquifers with mass transfer limitations under various hydrogeological and operational conditions. Simple and effective relationships between transport parameters and ASR operational parameters are derived to quantify the effectiveness and ascertain the potential of ASR systems with mass transfer limitations.(3) Effects of hydrogeological and operational parameters on ASR efficiency are assessed in homogeneous/stratified, isotropic/anisotropic coastal aquifers. Effects of transverse dispersion are particularly investigated in such aquifers.(4) Finally, we test and study an innovative ASR scheme for improving the RE in brackish aquifers: injection through a fully-penetrated well and recovery through a partially-penetrated well.

Although there are some carbon capture and storage (CCS-CO2 sequestration) projects in all over the world, feasibility problems exist due to the high economical issues. The aim of this study is to evaluate the feasibility of a potential CCS project where the source of CO2 is Afsin Elbistan Thermal Power Plant. Selection of candidate sites in the vicinity of Diyarbakir, Batman and Adiyaman regions depends on sequestration criteria. According to sequestration criteria, CCS can be applied to &Ccedil / aylarbasi mature oil field, Midyat saline aquifer and Dodan CO2 gas field. Disposing of CO2 from the source of Afsin Elbistan Thermal Power Plant is analyzed by pipeline and tanker. CO2 capturing technologies are determined from published literature. CO2 transportation can be applied by pipeline or tanker. CO2 transportation cost by pipeline and tanker are compared. It has been calculated that, transportation by pipeline is more economical compared to tanker transportation. It is further found that the number of boosting pump stations, the length of the pipeline and CO2 mass flow rate are the issues that alter the economical aspect in the pipeline transportation. The transportation costs by tankers depend on fuel cost, distance, tanker storage capacity, pin-up cost and CO2 storage facilities. The final part of CCS project is injection and storage of CO2 to the candidate areas. Reservoir parameters which are reservoir temperature, viscosity, permeability, reservoir pressure, reservoir thickness, CO2 density mass flow rate and injection pipe diameter determine the number and cost of the injection wells.

Geological sequestration of CO₂ in deep saline reservoirs is one of the ways to reduce its continuous emission into the atmosphere to mitigate the greenhouse effect. The effectiveness of any CO₂ sequestration operation depends on pore volume and the sequestration efficiency of the reservoir. Sequestration efficiency is defined here as the maximum storage with minimum risk of leakage to the overlying formations or to the surface. This can be characterized using three risk parameters i) the time the plume takes to reach the top seal; ii) maximum lateral extent of the plume and iii) the percentage of mobile CO₂ present at any time. The selection among prospective saline reservoirs can be expedited by developing some semi-analytical correlations for these risk parameters which can be used in place of reservoir simulation study for each and every saline reservoir. Such correlations can reduce the cost and time for commissioning a geological site for CO₂ sequestration. To develop such correlations, a database has been created from a large number of compositional reservoir simulations for different elementary reservoir parameters including porosity, permeability, permeability anisotropy, reservoir depth, thickness, dip, perforation interval and constant pressure far boundary condition. This database is used to formulate different correlations that relate the sequestration efficiency to reservoir properties and operating conditions. The various elementary reservoir parameters are grouped together to generate different variants of gravity number used in the correlations. We update a previously reported correlation for time to hit the top seal and develop new correlations for other two parameters using the newly created database. A correlation for percentage of trapped CO₂ is also developed using a previously created similar database. We find that normalizing all risk parameters with their respective characteristic values yields reasonable correlations with different variants of gravity number. All correlations confirm the physics behind plume movement in a reservoir. The correlations reproduce almost all simulation results within a factor of two, and this is adequate for rapid ranking or screening of prospective storage reservoirs. CO₂ injection in saline reservoirs on the scale of tens of millions of tonnes may result in fracturing, fault activation and leakage of brine along conductive pathways. Critical contour of overpressure (CoP) is a convenient proxy to determine the risk associated with pressure buildup at different location and time in the reservoir. The location of this contour varies depending on the target aquifer properties (porosity, permeability etc.) and the geology (presence and conductivity of faults). The CoP location also depends on relative permeability, and we extend the three-region injection model to derive analytical expressions for a specific CoP as a function of time. We consider two boundary conditions at the aquifer drainage radius, constant pressure or an infinite aquifer. The model provides a quick tool for estimating pressure profiles. Such tools are valuable for screening and ranking sequestration targets. Relative permeability curves measured on samples from seven potential storage formations are used to illustrate the effect on the CoPs. In the case of a constant pressure boundary and constant rate injection scenario, the CoP for small overpressures is time-invariant and independent of relative permeability. Depending on the relative values of overall mobilities of two-phase region and of brine region, the risk due to a critical CoP which lies in the two-phase region can either increase or decrease with time. In contrast, the risk due to a CoP in the drying region always decreases with time. The assumption of constant pressure boundaries is optimistic in the sense that CoPs extend the least distance from the injection well. We extend the analytical model to infinite-acting aquifers to get a more widely applicable estimate of risk. An analytical expression for pressure profile is developed by adapting water influx models from traditional reservoir engineering to the "three-region" saturation distribution. For infinite-acting boundary condition, the CoP trends depend on same factors as in the constant pressure case, and also depend upon the rate of change of aquifer boundary pressure with time. Commercial reservoir simulators are used to verify the analytical model for the constant pressure boundary condition. The CoP trends from the analytical solution and simulation results show a good match. To achieve safe and secure CO₂ storage in underground reservoirs several state and national government agencies are working to develop regulatory frameworks to estimate various risks associated with CO₂ injection in saline aquifers. Certification Framework (CF), developed by Oldenburg et al (2007) is a similar kind of regulatory approach to certify the safety and effectiveness of geologic carbon sequestration sites. CF is a simple risk assessment approach for evaluating CO₂ and brine leakage risk associated only with subsurface processes and excludes compression, transportation, and injection-well leakage risk. Certification framework is applied to several reservoirs in different geologic settings. These include In Salah CO₂ storage project Krechba, Algeria, Aquistore CO₂ storage project Saskatchewan, Canada and WESTCARB CO₂ storage project, Solano County, California. Compositional reservoir simulations in CMG-GEM are performed for CO₂ injection in each storage reservoir to predict pressure build up risk and CO₂ leakage risk. CO₂ leakage risk is also estimated using the catalog of pre-computed reservoir simulation results. Post combustion CO₂ capture is required to restrict the continuous increase of carbon content in the atmosphere. Coal fired electricity generating stations are the dominant players contributing to the continuous emissions of CO₂ into the atmosphere. U.S. government has planned to install post combustion CO₂ capture facility in many coal fired power plants including W.A. Parish electricity generating station in south Texas. Installing a CO₂ capture facility in a coal fired power plant increases the capital cost of installation and operating cost to regenerate the turbine solvent (steam or natural gas) to maintain the stripper power requirement. If a coal-fired power plant with CO₂ capture is situated over a viable source for geothermal heat, it may be desirable to use this heat source in the stripper. Geothermal brine can be used to replace steam or natural gas which in turn reduces the operating cost of the CO₂ capture facility. High temperature brine can be produced from the underground geothermal brine reservoir and can be injected back to the reservoir after the heat from the hot brine is extracted. This will maintain the reservoir pressure and provide a long-term supply of hot brine to the stripper. Simulations were performed to supply CO₂ capture facility equivalent to 60 MWe electric unit to capture 90% of the incoming CO₂ in WA Parish electricity generating station. A reservoir simulation study in CMG-GEM is performed to evaluate the feasibility to recycle the required geothermal brine for 30 years time. This pilot study is scaled up to 15 times of the original capacity to generate 900 MWe stripping system to capture CO₂ at surface. / text

In spite of the large number of research works on carbon capture and sequestration (CCS), the migration and behaviour of CO2 in the subsurface (i. e. strata below the earth's surface) still needs further understanding and investigations with the aim of encouraging the governmental policy makers to adopt CCS technology as one of the most viable means to tackle the global warming threats. In this research work, a series of numerical simulations has been carried out using STOMP-CO2 simulation code to determine the flow behaviour and ultimate fate of the injected supercritical carbon dioxide (scCO2) into saline aquifers in medium terms of storage (i. e. few thousand years). The characteristics of the employed simulator, including the mathematical algorithm, governing equations, equations of states and phase equilibria calculations are explained in details.

Of all the strategies to reduce carbon emissions, carbon dioxide (CO₂) geological sequestration is an immediately available option for removing large amounts of the gas from the atmosphere. However, our understanding of the transition behavior between Forchheimer and Darcy flow through porous media during CO₂ injection is currently very limited. In addition, the kinetic mass transfer of SO₂ and CO₂ from CO₂ stream to the saline and the fully coupling between the changes of porosity and permeability and multiphase flow are two significant dimensions to investigate the brine acidification and the induced porosity and permeability changes due to SO₂ co-injection with CO₂. Therefore, this dissertation develops a multiphase flow, contaminant transport and geochemical model which includes the kinetic mass transfer of SO₂ into deep saline aquifers and obtains the critical Forchheimer number for both water and CO₂ by using the experimental data in the literature. The critical Forchheimer numbers and the multiphase flow model are first applied to analyze the application problem involving the injection of CO₂ into deep saline aquifers. The results show that the Forchheimer effect would result in higher displacement efficiency with a magnitude of more than 50% in the Forchheimer regime than that for Darcy flow, which could increase the storage capacity for the same injection rate and volume of a site. Another merit for the incorporation of Forchheimer effect is that more CO₂ would be accumulated in the lower half of the domain and lower pressure would be imposed on the lower boundary of the cap-rock. However, as a price for the advantages mentioned above, the injection pressure required in Forchheimer flow would be higher than that for Darcy flow. The fluid flow and contaminant transport and geochemical model is then applied to analyze the brine acidification and induced porosity and permeability changes due to SO₂ co-injection. The results show that the co-injection of SO₂ with CO₂ would lead to a substantially acid zone near the injecting well and it is important to include the kinetic dissolution of SO₂ from the CO₂ stream to the water phase into the simulation models, otherwise considerable errors would be introduced for the equilibrium assumption. This study provides a useful tool for future analysis and comprehension of multiphase Darcy-Forchheimer flow and brine acidification of CO₂ injection into deep saline aquifers. Results from this dissertation have practical use for scientists and engineers concerned with the description of flow behavior, and transport and fate of SO₂ during SO₂ co-injection with CO₂ in deep saline aquifers.