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Abstract The goal of this work is to develop an improved model of CO2 bubble rise through porous media in the deep subsurface. Under the geologic carbon sequestration (GCS) conditions of interest, a rising parcel of CO2 will be subject to at least three dynamic forces:buoyant forces; surface tension forces; and shear drag forces. To fully characterize these, this work involved several experimental measurements focused on the second and third forces in particular. To better understand the effect of shear drag forces, the viscosity of brines was explored under bubbly flow scenarios to understand the rheological conditions that might impact leakage. To better understand the role of surface tension forces on influencing flow, contact angle measurements were carried out for a range of relevant mineral, brine, CO2 combinations. Predicting leakage from geologic carbon sequestration sites is difficult because of the large length scales that are involved and because of the complex geophysics and geochemistry that a rising parcel of CO2 will be subject to as it travels to the surface. To better understand how quickly and where a parcel of CO2 is likely to escape, better modeling tools are needed. These tools must be based on experimental results collected for GCS-relevant conditions. The results of the brine viscosity work suggest that under vapor liquid equilibrium (VLE) conditions CO2-brine mixtures will exhibit complex viscoelastic behavior. This is because CO2 bubbles in the matrix will respond to the varying levels of shear that will exist in the porous media to resist flow. Similarly, the contact angle measurements suggest that CO2 is less wetting of some common minerals and clays that prevail near GCS sites. The experimental results described here will be used to describe an enhanced model of CO2 vertical flow through the subsurface. At smaller scales, this enhanced model could help explain preferential flow pathways and potential hysteresis that could influence leakage from GCS sites. At larger scales, the results of this work could contribute to more accurate prediction tools for managing the risk associated with GCS. INTRODUCTION Geologic carbon sequestration (GCS) has been discussed as a scalable and economically viable approach for keeping large volumes of anthropogenic carbon dioxide out of the atmosphere (Chen, Gingras et al. 2003; Eccles, Pratson et al. 2009). In GCS, the flue gas from power plants and other point sources is captured, separated, compressed, transported and injected into porous geologic formations several kilometers under the surface. Candidate formations are bound by impermeable layers that prevent the buoyant rise of the injected CO2 and are generally filled with brines that would have little other economic value (Widjajakusuma, Biswal et al. 1999; Kneafsey and Pruess 2010). At these depths, hydrostatic pressures and geothermal temperatures are large and the CO2 exists in the liquid or supercritical phase where it would intermingle with the endogenous brines (Chen and Zhang 2010). The densities of CO2 under all states are lower than that of the native brines and so the parcel of CO2 will be subject to buoyant forces. The CO2 could escape under several scenarios including leakage through abandoned well bores, heterogeneities in the bounding formation, groundwater flow to shallower unconfined aquifers and other pathways (Figure 1 (left)) (Nordbotten, Celia et al. 2004; Zhang, Oldenburg et al. 2009; Wollenweber, Alles et al. 2010).
- North America > United States (0.94)
- Europe > Norway > Norwegian Sea (0.24)
Active CO2 Reservoir Management for CO2 Capture, Utilization, and Storage: An Approach to Improve CO2 Storage Capacity and to Reduce Risk
Buscheck, Thomas A. (Lawrence Livermore Natlional Laboratory) | Friedmann, Samuel Julius (Lawrence Livermore Natl. Lab) | Sun, Yunwei (Lawrence Livermore National Laboratory) | Chen, Mingjie (Lawrence Livermore National Laboratory) | Hao, Yue (Lawrence Livermore National Laboratory) | Wolery, Thomas J. (Lawence Livermore National Laboratory) | Aines, Roger D. (Lawrence Livermore National Laboratory)
Abstract CO2 capture, utilization, and storage (CCUS) in deep geological formations is regarded as a promising means of lowering the amount of CO2 emitted to the atmosphere and thereby mitigating global climate change. For commercial-scale CO2 injection in saline formations, pressure buildup can limit CO2 storage capacity and security. Issues of interest include the potential for CO2 leakage to the atmosphere, brine migration to overlying potable aquifers, and pore-space competition with neighboring subsurface activities. Active CO2 Reservoir Management (ACRM) combines brine production with CO2 injection to relieve pressure buildup, increase injectivity, spatially and temporally constrain brine migration, and enable beneficial utilization of produced brine. Useful products may include freshwater, cooling water, make-up water for oil, gas, and geothermal reservoirs, and electricity generated from extracted geothermal energy. By controlling pressure buildup and fluid migration, ACRM can limit interactions with neighboring subsurface activities, reduce pore-space competition, and allow independent assessment and permitting. ACRM provides benefits to reservoir management at the cost of extracting brine. The added cost must be offset by the added benefits to the storage operation and/or by creating new, valuable uses that reduce the total added cost. We review potential uses of produced brine and conduct a numerical study of potential reservoir benefits. Using the NUFT code, we investigate CO2-injector/brine-producer strategies to improve CO2 storage capacity and minimize interference with neighboring subsurface activities. Performance measures considered in this study include magnitude of vertical brine migration and areal extent and duration of pressure buildup. We consider ranges of CO2-storage-formation thickness and permeability and caprock-seal thickness and permeability, comparing injection-only cases with ACRM cases with a volumetric production-to-injection ratio of one. The results of our study demonstrate the potential benefits of brine production to CO2-storage operations. The economic value of these benefits will require more detailed, site-specific analyses in future studies. INTRODUCTION Stabilizing atmospheric CO2 concentrations for climate change mitigation will require CO2 capture and storage (CCS) implementation being increased by several orders of magnitude over the next two decades (Fig. 3 of IEA, 2009). CCS in deep geological formations is regarded as a promising means of reducing atmospheric CO2 emissions (IEA, 2007). For widespread deployment of commercial-scale CCS to be achievable, several implementation barriers must be addressed. Previously identified barriers, such as CO2 capture cost, absence of CO2 transport network, legal and regulatory barriers, sequestration safety, and public acceptance are discussed in the Special Report on CCS (SRCCS) (IPCC, 2005). Implementation barriers receiving more recent attention are water-use demands from CCS operations and pore-space competition with emerging activities, such as shale-gas production (Court et al., 2011a). For commercial-scale CO2 injection in saline formations, pressure buildup can be a limiting factor in CO2 storage capacity, security, and safety. Primary issues for sequestration security and safety include the potential for CO2 leakage to the atmosphere, brine migration to overlying water-supply aquifers, and induced seismicity (Bachu, 2008; Carroll et al., 2008; Morris et al., 2011; Rutqvist el al., 2007). A key issue for storage capacity is pore-space competition with neighboring subsurface activities, including other CCS operations. A comprehensive review is presented by Court et al. (2011a) of progress, since the SRCCS, on several of these CCS implementation challenges: water management; sequestration safety; pore-space competition; legal and regulatory; and public acceptance.
- Europe > Norway > Norwegian Sea (0.45)
- North America > United States > California (0.28)
- Overview (0.86)
- Research Report > New Finding (0.48)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock (0.48)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > CO2 capture and management (1.00)
Abstract CO2 sequestration in mature oil and gas reservoirs is attractive due to the possible cost offsets from enhanced oil recovery (EOR). In this work we develop a 3D reservoir model and fluid flow simulation of the fractured Tensleep Formation using geomechanical constraints in advance of a proposed CO2-EOR and sequestration pilot at Teapot Dome Oil Field, WY. The objective is to model the migration of the injected CO2, and to obtain limits on rates and volumes to be injected, without compromising seal integrity. Additionally we want to investigate the effect of fractures on the permeability and mobility of CO2. The pilot planned to inject 1 MMcfd of supercritical CO2 for six weeks. The results indicate that CO2 buoyancy and mobility could pose problems to EOR performance in this highly fractured reservoir. The injected CO2 will rapidly rise to the top layers, above the main producing interval, accumulating in the fractures. It takes almost a year to start saturating the fractures in the target interval and almost two years to penetrate into the matrix. Furthermore a well control strategy would be necessary to improve oil recovery without circulating CO2. Incremental oil production is predicted to be less than 10% or 30% if double the amount of CO2 is injected in twice the amount of time. Regarding storage capacity, the trap could hold up to 2 wells injecting 1 MMcfd each, for 15 years. This could sequester ~5x105 tonnes of CO2 equivalent to a small power plant emitting ~37,800 tonnes/year. INTRODUCTION CO2 injection has been used as a commercial process for enhanced oil recovery (EOR) since the 1970s and is the second-most applied EOR process in the world (Jarrell et al., 2002). Traditionally, the goal has been to recover the maximum amount of oil from the reservoir while injecting the minimum amount of gas, because the cost of CO2 affects the profitability of the project. However, when the objective is to combine EOR and CO2 sequestration, different CO2 flooding designs will have to be implemented in order to increase the amount of CO2 left behind when production stops (Kovscek and Cakici, 2005). A CO2-EOR and Sequestration pilot was proposed at Teapot Dome Oil Field, targeting the fractured Tensleep Fm. in a three-way closure trap against a bounding fault, termed the S1 fault (Figure 1). A comprehensive geomechanical analysis performed in the system (Chiaramonte et al., 2006 and 2008) found that the S1 fault does not appear to be at risk of reactivation and that the caprock integrity is not at risk from the buoyancy pressure of the maximum CO2 column height that the formation can hold. The presence of critically stressed minor faults and fractures in the reservoir was also established (Chiaramonte et al., 2011). If these minor faults are reactivated, they could enhance the permeability of the reservoir and create permeability anisotropy inside it. In the present work, we develop a stochastic 3D reservoir model of the Tensleep Formation, as input for a fluid flow simulation, using the geomechanical constraints estimated by Chiaramonte et al., (2006 and 2008). Our objective is to model the migration of the injected CO2, as well as to obtain limits on the rates and volumes of CO2 that can be injected, without compromising seal integrity. Additionally we want to investigate the effect of fractures on the permeability and mobility of CO2.
- North America > United States > Wyoming > Natrona County (0.86)
- North America > United States > Oklahoma > Osage County (0.54)
- Geology > Structural Geology (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
- North America > United States > Wyoming > Powder River Basin > NPR-3 > Teapot Dome Field > Wall Creek Formation (0.99)
- North America > United States > Wyoming > Powder River Basin > NPR-3 > Teapot Dome Field > Tensleep Formation (0.99)
- North America > United States > Wyoming > Powder River Basin > NPR-3 > Teapot Dome Field > Sussex Formation (0.99)
- (6 more...)
Abstract The National Energy Technology Laboratory (NETL) is funding research aimed at improving the performance and reducing the cost of oxycombustion technology for low-carbon power generation. The objective of this study is to guide oxycombustion research in areas that can provide the largest benefits in electricity cost and plant performance. The advanced oxycombustion technologies evaluated in this study are categorized into four major areas: advanced boiler design, advanced oxygen production, advanced flue gas treatment, and innovative CO2 compression concepts. This report contains the results of a techno-economic study of nine configurations: eight cases employing advanced oxycombustion technologies and a reference case employing what is considered to be current technology capable of facilitating an oxycombustion power generation system. In order to meet the challenges of reducing greenhouse gas emissions, DOE/NETL has established carbon capture and utilization/storage (CCUS) goals requiring that advanced CCUS technologies will be capable of capturing 90% of CO2 generated in a fossil-based power generation system for less than 35 percent increase in electricity cost of an equivalent plant without carbon capture. The advanced oxycombustion technologies studied were evaluated to determine if they could meet the DOE goal. The electricity costs of the advanced technology cases were compared to those of an air-fired, supercritical boiler with no carbon capture. None of the advanced technologies were shown to independently meet the DOE goal. However, the combined effect of including all advanced technologies in the same plant is shown to exceed the DOE CCUS goal. As might be expected, improvements in oxygen separation technologies, sulfur-tolerant materials, and high temperature materials were found to substantially improve oxycombustion performance. This study attempts to provide systematic quantification of the benefit that future research and development directed at advancing the performance of these key technology areas will have on a low-carbon power generation industry. INTRODUCTION The rising concentration of carbon dioxide (CO2) in the environment has been widely documented. Levels of CO2 in the atmosphere have shown a steady rise from approximately 300 parts per million (ppm) in 1940 to more than 370 ppm today (1). At the same time, various studies have documented noticeable changes in climate during recent years, and model predictions suggest that CO2 levels play a role in these climate variations (2). Given the potential implications surrounding global climate change and increasing concentrations of CO2 in the atmosphere, technology and policy options are being investigated for mitigating CO2 emissions.
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Power Industry > Utilities (0.86)
Abstract CO2 Capture and Storage (CCS) has been suggested as a key component of an effective climate strategy. Hence, a significant amount of research in the United States is aimed at capturing and storing CO2. As a part of a near-commercial scale demonstration by the Southwest Regional Partnership on Carbon Sequestration (SWP), a net of ~ 2.9 million tons of CO2 will be injected into the Navajo formation at Gordon Creek, Utah over a period of 4 years, starting in 2013, for permanent sequestration. The Navajo formation is an aquifer that is currently used for disposal of produced water from Gordon Creek natural gas production. In order to achieve CO2 sequestration, it is important to ensure that there is no significant leakage to the surface or underground sources of drinking water (USDW). Leakage can occur by a variety of mechanisms such as high permeability pathways i.e. faults, failure of an existing plugged well and exceeding formation fracture pressure. Incomplete characterization of the field may result in undetected transmissive or non-transmissive faults in the aquifer. Transmissive faults create a permeability pathway for the CO2 to leak back to the surface or into overlying formations while non-transmissive faults limit the CO2 storage volume. Additionally, the presence of faults affect the hydrodynamic and geochemical trapping mechanisms in the aquifer. This work investigates the impact of faults on the storage of CO2 in an aquifer. INTRODUCTION Atmospheric levels of CO2 have been increasing due to anthropogenic activities. In order to mitigate the increasing CO2 levels in the atmosphere, the United Nations Intergovernmental Panel on Climate Change (IPCC) suggested CCS as one of the best practices (Metz, Davidson, Coninck, Loos and Meyer, 2005). Other mitigation options include improving energy efficiency, switching to less carbon-intensive fuels, nuclear energy, renewable energy, enhancement of biological sinks, and reduction of non-CO2 greenhouse gas emissions (Metz, Davidson, Coninck, Loos and Meyer, 2005). A significant amount of research in the United States is directed at CCS. Potential areas for capture and storage have been identified: Potential capture sites for CO2 are power generation plants, cement production facilities, refineries, iron and steel industries, and petrochemical indus-tries. The potential storage sites identified include depleted oil and gas reservoirs, un-minable coal seams and deep saline aqui-fers. The captured CO2 could be transferred from the source to the storage site by means of pipelines or shipping. The technol-ogy for transferring CO2 into subsurface formations is mature and has been used by the petroleum industry for Enhanced Oil Recovery for many years. In order to investigate the best solution for capture and storage of CO2, The US Department of Energy (DOE), has funded a network of seven regional partnerships that include 350+ state agencies, universities and private companies, spanning 43 states, three Native American organizations, and four Canadian provinces. Researchers of each partnership will investigate best solutions for capturing and storing CO2 in their region. The seven partnerships include Big Sky Regional Carbon Seques-tration Partnership (Big Sky), Plains CO2 Reduction Partnership (PCOR), Midwest Geological Sequestration Consortium (MGSC), Midwest Regional Carbon Sequestration Partnership (MRCSP), Southeast Regional Carbon Sequestration Partner-ship (SECARB), Southwest Regional Partnership on Carbon Sequestration (SWP) and the West Coast Regional Carbon Se-questration Partnership (WESTCARB).
- North America > United States > Utah (1.00)
- North America > United States > Texas > Kleberg County (0.24)
- North America > United States > Texas > Chambers County (0.24)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Wyoming > Uinta Basin (0.99)
- North America > United States > Utah > Uinta Basin > Gordon Creek Field (0.99)
- North America > United States > Colorado > Uinta Basin (0.99)
- (10 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Abstract When injected in deep saline aquifers or depleted oil and gas reservoirs, supercritical CO2 remains mobile and can, therefore, migrate through any conduits or fractures. In addition, public opinion, regulations and the lack of space for CO2 injection in some densely populated regions of the world such as the Japanese archipelago encourage investigating other alternatives such as carbon dioxide sequestration in deepwater sub-seabed formations. This paper intends to present a technical feasibility study of CO2 sequestration in deepwater sediments offshore Japan. The main processes, technical requirements, technologies and structures that are currently available to transport and inject liquid CO2 successfully in sub-seabed formations below 9,000 feet of water (ห2,750 meters) are first discussed. Then, three storage sites situated offshore Japan; one located in the Northwest Pacific Ocean near the island of Shikoku; another located in the Sea of Japan near the island of Honshu; and the last one located farther in the Northwest Pacific Ocean in ultra-deepwater (18,000 feet); are selected to conduct reservoir simulations. From this study, it appears that CO2 capturing technologies and transporting means seem to be at a mature stage. Also, current and newest 5th and 6th generation drilling vessels are estimated to be capable of drilling very shallow wells in water depths greater than 9,000 feet and even in ocean waters as deep as 18,000 feet if new materials such as titanium or composite for riser systems were to be deployed for both the drilling and CO2 injection operations. However, CO2 storing and injection facilities are not available yet to unload large quantities of CO2 offshore. As a result, some concepts should be designed, qualified and tested for these large scale operations within the next decade to demonstrate through pilot projects the technical feasibility of CO2 sequestration in sub-seabed geological formations. Additionally, the main findings from this comparative study and reservoir simulations conducted at three different sites located offshore Japan confirm that a significant part of ultra-deepwater regions with at least 9,000 feet of ocean water and planar seafloor are appropriate for CO2 storage. Secondly, reservoir models confirm that due to high pressures and low temperatures reigning at water depths greater than 9,000 feet, the liquid CO2 injected in the first few hundred feet of sediments has a higher density than the surrounding formation pore-fluid and therefore remains buoyantly trapped under certain condition of geothermal gradient, sediments permeability and formation pressure and; hence constitute a valid and safe CO2 storage candidate.
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract The cement industry is one of the largest producers of CO2 in the world. The widespread and common use of concrete as a building material has allowed for continued growth of the cement industry. Worldwide cement production is expected to almost double by 2050. This paper explains some of the basics of the global cement industry providing data on where cement is made today and in the future. The paper also provides an explanation of the sources of CO2 emissions in cement manufacture. The paper explores the International Energy Agency's (IEA) "cement technology roadmap" for CO2 emissions reductions in the cement industry. This roadmap was developed under the guidance of World Business Council for Sustainable Development and the Cement Sustainability Initiative. It calls for roughly a two-fold reduction in specific CO2 emissions per ton of cement produced. Each of the three traditional levers for the industry; energy efficiency, alternative fuels, and clinker substitution will be explained. The limits for each lever will be identified, thus identifying the gap that will exist after current known levers are exhausted. As a main conclusion, we can say that given the magnitude of the challenge ahead, even with the sectorial approach promoted by the IEA, the cement industry will likely have to rely heavily on carbon capture and storage to meet the CO2 reduction targets. This would imply very high operating and capital costs for the industry and mandates further innovation. Lafarge's AetherTM cement is one such example with a CO2 footprint reduced by up to 30%. INTRODUCTION In this article, unless otherwise mentioned, we use units from the International System. The cement industry is one of the largest producers of CO2 in the world. According to IEA data [IEA(2010)], in 2007, the cement industry was responsible for 2.0Gt (billion tons) of CO2 emissions which represents a share of 26% of the industrial emissions of CO2 (7.6Gt) and a share of 7% of the total manmade CO2 emissions (29Gt). The cement manufacturing process requires large amounts of thermal and electrical energy. This energy requirement combined with the widespread use of concrete in global construction defines the magnitude of the challenge at hand. Defining the terms Cement or more precisely Ordinary Portland Cement (OPC) is a manufactured inorganic substance. Cement is the powdered binder that is used almost exclusively to produce concrete. Concrete is produced by adding cement to a mixture of sand, aggregate and water. Different chemical admixtures are often added to enhance specific properties of the concrete. Cement is the "true" binder that transforms the mixture into the artificial stone known as concrete. The cement provides cohesion and strength to the mix as well as low permeability and high durability.
- Materials > Construction Materials (1.00)
- Construction & Engineering (1.00)
- Energy > Oil & Gas > Upstream (0.46)
The Rock Springs Uplift: A Premier CO2 Storage Site in Wyoming
Surdam, Ronald C. (U. of Wyoming) | Dahl, S. (Los Alamos Natl. Lab) | Hurless, R. (Los Alamos Natl. Lab) | Jiao, Zunsheng (U. of Wyoming) | Ganshin, Yuri (U. of Wyoming) | Bentley, R. (Los Alamos Natl. Lab) | Garcia-Gonzalez, M. (Los Alamos Natl. Lab)
Abstract With global energy consumption increasing at about 25% per decade, it is essential for energy exporting states like Wyoming to optimize energy development during the 21st century in order to safeguard our nation's economy and energy security. Without regulation, annual global CO2 emissions will double by 2030 (Figure 1). In this case, over a very short time period, the world's largest economies will either have to abandon fossil fuels as a source of energy, or capture and geologically store CO2 emissions. In the future, the results from the Wyoming Carbon Underground Storage Project (WY-CUSP) will prove critical to the optimization of responsible energy resource development in Wyoming and other Rocky Mountain states. The coal extraction, enhanced oil recovery, coal-fired electricity generation, and coal-to-chemical industries will need either CO2 or a place to store CO2. To facilitate deployment of any new and/or improved energy delivery technologies and associated industries in Wyoming, the state must document the existence of available commercial CO2 storage capacity, along with infrastructure to transport CO2 from its source to the storage site, and finally to the end point of use.
- Materials > Metals & Mining > Coal (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Wyoming > Bighorn Basin (0.99)
- North America > United States > Montana > Powder River Basin (0.99)
- (28 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Abstract Combating climate change by mitigation of release of the anthropogenic greenhouse gases has attracted worldwide attention towards research and policy formulations. One such approach utilizes the geological sequestration of carbon dioxide into coal beds which is a value addition process, capable of enhancing the yield of coalbed methane (CBM) in producing reservoirs. CO2 is preferentially adsorbed onto the microporous structure of coal seams and it displaces the methane molecule from the adsorption sites, thereby enhancing the production of the low carbon eco-friendly fuel. In this study, a finite difference based reservoir simulator, COMET3, has been utilized for construction of underground coal bed scenario for Indian seams. Numerical modeling involves solving complex equations used to describe some physical process by iterative approximate solutions. Such simulation is worked out for underground coal of Lower Gondwana sequence in Jharkhand state in India. Detailed field work was carried out to collect samples and field data. Laboratory tested parameters and some from published data were utilized for construction of the numerical model. The best fit model was developed for estimation of the volumes of gases involved in CO2 enhanced coalbed methane recovery. It also gives a detailed analysis of distribution of gases with time and space. The results obtained from the simulation are quite encouraging and ascertain that the process of CO2 enhanced CBM recovery seems to be technically feasible for Indian scenario also. The simulation was executed for a period of 20 years to understand the space-time disposition of injected CO2 and recovery of methane from the reservoirs. It is quantified in this study that for the chosen dimensions of coal block, a total of 15.1 bcf of CO2 can be injected into the reservoir and approximately 5.0 bcf of methane can be recovered.
- North America > United States (0.95)
- Asia > India > Jharkhand (0.34)
- North America > Canada > Alberta (0.29)
- Materials > Metals & Mining > Coal (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > India > Tripura > Assam-Arakan Basin (0.99)
- Asia > India > Tamil Nadu > Bay of Bengal > Cauvery Basin (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Bikaner Nagaur Basin (0.99)
- (4 more...)
ABSTRACT CO2 compression is considered as one of the challenges in CO2 capture and sequestration (CCS). In enhanced oil recovery (EOR) applications where CO2 is pressurized to supercritical pressure (e.g. 150 bar) before injection into a well, CO2 compression could reduce natural gas combined cycle power plants net power by about 4%. In this paper, several CO2 pressurization strategies, such as compression or liquefaction and pumping using an open cycle or closed cycles, were explored and evaluated. New CO2 liquefaction cycles based on single refrigerant and cascade refrigerants were developed and modeled using HYSYS software. The developed models were validated against experimental data. The considered refrigerants for CO2 liquefaction are NH3, CO2, C3H8 and R134a. One of the developed vapor compression CO2 liquefaction cycles that use NH3 as a refrigerant at an optimized liquefaction pressure resulted in 5.1% less power consumption than the conventional multi-stage compression cycle as well as 27.7% less power consumption than the open CO2 liquefaction cycle. Sensitivity analysis was carried out to explore the effect of heat exchangers pressure drop, compressors isentropic efficiency and seawater temperature on the power savings. The results show that the developed liquefaction cycle outperforms the conventional multi-stage compression cycle in almost all cases explored.
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- (3 more...)