Browsing by Subject "CO2-EOR"

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CO₂ trapping mechanisms assessment using numerical and analytical methods
(2020-01-30) Hosseininoosheri, Pooneh; Lake, Larry W.; Werth, Charles J.
Carbon capture and storage (CCS) is a proven technique for reducing greenhouse gas emissions and climate change. Although monitoring shows that CO₂ can be safely stored underground, CO₂ leakage is still of concern. Therefore, understanding and forecasting the CO₂ distribution over a geological time is necessary to assess the storage performance and related risks. To understand the CO₂ distribution during or/and after a CCS process, four main trapping mechanisms have been introduced: stratigraphic (structural) trapping, residual trapping, solubility trapping, and mineral trapping. The relative contribution of each mechanism in CO₂ sequestration is expected to change over time as CO₂ migrates and reacts with formation rock and fluids. Although structural trapping is the most active trapping mechanism after CO₂ injection, some of the structurally trapped CO₂ dissolves into water with the rest becoming residual over time. Both the residual and dissolved CO₂ then react with rock and trap some of the CO₂, the process of which is recognized as part of mineral trapping. The relative contribution of different trapping mechanisms depends on different parameters, such as the type of geologic sink (i.e., saline aquifers, hydrocarbon reservoirs), and the properties of the reservoir fluids contained. Additionally, in the case of CO₂-EOR/storage the importance of different trapping mechanisms may change depending on the CO₂ injection strategy (e.g., water alternating gas, WAG; continuous gas injection, CGI; water curtain injection, WCI). In this dissertation, I investigate the CO₂ trapping mechanisms in two CCS processes: CO₂-EOR/storage and CO₂ injection in dipping aquifers. First, I investigate the CO₂ trapping mechanisms during and after a CO₂-EOR process using reservoir simulation. The main purpose is to answer questions associated with the relationship between EOR operational strategies and CO₂ utilization ratios, and to understand the impact of the different CO₂ trapping mechanisms on this relationship. To answer these questions, I integrate three main elements of field assessment: physical field characterization, production and pressure history, and reservoir simulation. I use this method to model and compare two fields that represent two different reservoir settings: Cranfield (representative of the U.S. Gulf Coast sandstone reservoirs) and SACROC (representative of the Permian Basin carbonate reservoirs). CGI is the original operating strategy in Cranfield and WAG is the original operating strategy applied in the SACROC unit. Second, I investigate the impact of relative permeability on the trapping mechanisms in a CO₂-EOR process using fractional flow analysis and reservoir simulation. I use the fractional flow theory for miscible displacement to analytically and graphically analyze the distribution of CO₂ trappings. I use the Cranfield model to show the impact of relative permeability on field predictions. I discuss the relative permeability impact on four different CO₂ injection schemes: continuous gas injection (CGI), water alternating gas injection (WAG), water curtain injection (WCI), and WCI+WAG. Third, I introduce a mathematical model, derived from force balance, to predict CO₂ plume migration in dipping aquifers. This model calculates the down and up-dip extension of CO₂ plume in the absence of trapping mechanisms. The force balance shows that there is a point in the down-dip flow where buoyancy and viscous forces are equal and the plume cannot extend further. However, in the up-dip flow, where the direction of viscous and buoyancy forces are the same, the plume migrates upward for an unlimited time. I validate the mathematical model against numerical simulation results. I introduce an effective relative permeability correlation to capture the competition between water and CO₂. I adjust the permeability of the aquifer to validate the mathematical model against heterogeneous cases. The results show that the heterogeneity-induced error is small if we use the near well-bore average permeability. I also investigate the effect of local capillary trapping on the plume shape. Using numerical simulation, I apply capillary trapping and show how capillary forces prevent the buoyant CO₂ from migrating up-dip.
Developments in modeling and optimization of production in unconventional oil and gas reservoirs
(2015-05) Yu, Wei; Sepehrnoori, Kamy, 1951-; Chin, Lee; Delshad , Mojdeh; Mohanty, Kishore K; Patzek, Tadeusz W
The development of unconventional resources such as shale gas and tight oil exploded in recent years due to two key enabling technologies of horizontal drilling and multi-stage fracturing. In reality, complex hydraulic fracture geometry is often generated. However, an efficient model to simulate shale gas or tight oil production from complex non-planar fractures with varying fracture width along fracture length is still lacking in the petroleum industry. In addition, the pore size distributions for shale gas reservoirs and conventional gas reservoirs are quite different. The diffusivity equation of conventional gas reservoirs is not adequate to describe gas flow in shale reservoirs. Hence, a new diffusivity equation including the important transport mechanisms such as gas slippage, gas diffusion, and gas desorption is required to model gas flow in shale reservoirs. Furthermore, there are high cost and large uncertainty in the development of shale gas and tight oil reservoirs because of many uncertain reservoir properties and fracture parameters. Therefore, an efficient and practical approach to perform sensitivity studies, history matching, and economic optimization for the development of shale gas and tight oil reservoirs is clearly desirable. For tight oil reservoirs, the primary oil recovery factor is very low and substantial volumes of oil still remain in place. Hence, it is important to investigate the potential of CO₂ injection for enhanced oil recovery, which is a new subject and not well understood in tight oil reservoirs. In this research, an efficient semi-analytical model was developed by dividing fractures into several segments to approximately represent the complex non-planar fractures. It combines an analytical solution for the diffusivity equation about fluid flow in shale and a numerical solution for fluid flow in fractures. For shale gas reservoirs, the diffusivity equation of conventional gas reservoirs was modified to consider the important flow mechanisms such as gas slippage, gas diffusion, and gas desorption. The key effects of non-Darcy flow and stress-dependent fracture conductivity were included in the model. We verified this model against a numerical reservoir simulator for both rectangular fractures and planar fracture with varying width. The well performance and transient flow regime analysis between single rectangular fracture, single planar fracture with varying width, and single curving non-planar fracture were compared and investigated. A well from Marcellus shale was analyzed by combining non-planar fractures, which were generated from a three-dimensional fracture propagation model developed by Wu and Olson (2014a), and the semi-analytical model. Contributions to gas recovery from each gas flow mechanism were analyzed. The key finding is that modeling gas flow from non-planar fractures as well as modeling the important flow mechanisms in shale gas reservoirs is significant. This work, for the first time, combines the complex non-planar fracture geometry with varying width and all the important gas flow mechanisms to efficiently analyze field production data from Marcellus shale. We analyzed several core measurements for methane adsorption from some area in Marcellus shale and found that the gas desorption behaviors of this case study deviate from the Langmuir isotherm, but obey the BET (Brunauer, Emmett and Teller) isotherm. To the best of our knowledge, such behavior has not been presented in the literature for shale gas reservoirs to behave like multilayer adsorption. The effect of different gas desorption models on calculation of original gas in place and gas recovery prediction was compared and analyzed. We developed an integrated reservoir simulation framework to perform sensitivity analysis, history matching, and economic optimization for shale gas and tight oil reservoirs by integrating several numerical reservoir simulators, the semi-analytical model, an economic model, two statistical methods, namely, Design of Experiment and Response Surface Methodology. Furthermore, an integrated simulation platform for unconventional reservoirs (ISPUR) was developed to generate multiple input files and choose a simulator to run the files more easily and more efficiently. The fracture cost was analyzed based on four different fracture designs in Marcellus shale. The applications of this framework to optimize fracture treatment design in Marcellus shale and optimize multiple well placement in Bakken tight oil reservoir were performed. This framework is effective and efficient for hydraulic fracture treatment design and production scheme optimization for single well and multiple wells in shale gas and tight oil reservoirs. We built a numerical reservoir model to simulate CO₂ injection using a huff-n-puff process with typical reservoir and fluid properties from the Bakken formation by considering the effect of CO₂ molecular diffusion. The simulation results show that the CO₂ molecular diffusion is an important physical mechanism for improving oil recovery in tight oil reservoirs. In addition, the tight oil reservoirs with lower permeability, longer fracture half-length, and more heterogeneity are more favorable for the CO₂ huff-n-puff process. This work can provide a better understanding of the key parameters affecting the effectiveness of CO₂ huff-n-puff in the tight oil reservoirs.
Environmental and Operational Performance of CO2-EOR as a CCUS Technology: A Cranfield Example with Dynamic LCA Considerations
(2019-01-31) Nunez-Lopez, Vanessa; Gil-Egui, Ramon; Hosseini, Seyyed A.
EOR Potential from CO2 Captured from Coal-Fired Power Plants in the Upper Cretaceous (Cenomanian) Woodbine Group, East Texas Basin, and Southeastern Texas Gulf Coast, USA
(2015) Ambrose, W.A.; Breton, C.; Nunez-Lopez, Vanessa; Gulen, G.
Evolution of CO2 Utilization Ratio and CO2 Storage under Different CO2 - EOR Operating Strategies: A Case Study on SACROC Unit Permian Basin
(2018) Hosseininoosheri, Pooneh; Hosseini, Seyyed A.; Nunez-Lopez, Vanessa; Lake, L.W.
Exploring the potential of carbon capture and storage-enhanced oil recover y as a mitigation strategy in the Colombian oil industry
(2020-03) Yanez, Edgar; Ramirez, Andrea; Nunez-Lopez, Vanessa; Castillo, Edgar; Faaij, Andre
Gas source attribution techniques for assessing leakage at geologic CO2 storage sites: Evaluating a CO2 and CH4 soil gas anomaly at the Cranfield CO2-EOR site
(2016) Anderson, J.S.; Romanak, Katherine D.; Yang, C.; Lu, J.; Hovorka, Susan D.; Young, M.H.
GPS-based monitoring of surface deformation associated with CO2 injection at an enhanced oil recovery site
(2015) Karegar, M.A.; Dixon, T.H.; Malservisi, R.; Yang, Q.; Hosseini, Seyyed A.; Hovorka, Susan D.
Identification of a representative dataset for long-term monitoring at the Weyburn CO2-injection enhanced oil recovery site, Saskatchewan, Canada
(2016) Gao, R.S.; Sun, Alexander Y.; Nicot, Jean-Phillipe
Impact of field development strategies on CO2 trapping mechanisms in a CO2– EOR field: A case study in the permian basin (SACROC unit)
(2018) Hosseininoosheri, Pooneh; Hosseini, Seyyed A.; Nunez-Lopez, Vanessa; Lake, L.W.
Impact of Relative Permeability Uncertainty on CO Trapping Mechanisms in a CO-EOR Process: A Case Study in the U.S. Gulf Coast Cranfield
(2019-04) Hosseininoosheri, Pooneh; Mehrabi, Mehran; Hosseini, Seyyed A.; Nunez-Lopez, Vanessa; Lake, Larry W.
Integrated Framework for Assessing Impacts of CO2 Leakage on Groundwater Quality and Monitoring-Network Efficiency: Case Study at a CO2 Enhanced Oil Recovery Site
(2015) Yang, C.; Hovorka, Susan D.; Trevino, Ramon H.; Delgado-Alonso, J.
Integration of reservoir simulation, history matching, and 4D seismic for CO2-EOR and storage at Cranfield, Mississippi, USA
(2016) Alfi, M.; Hosseini, Seyyed A.
Introduction to this special section: CO2 in the subsurface
(2020) Nunez-Lopez, Vanessa; Chiaramonte, Laura; Spikes, Kyle T.
Leveraging Geologic CO2 Storage Technology for CO2-EOR Management
(2012) Nunez-Lopez, Vanessa; Heiligenstein, Christopher; Hovorka, Susan D.; Muñoz Torres, Javier; Zeidouni, M.
Enhanced oil recovery (EOR) through CO2 injection has evolved from the laboratory testing and field piloting phases in the early 1970s to the widespread and refined operations of today. Over the last 20 years, geological CO2 storage (GCS) has emerged as a promising approach to dispose of large volumes of CO2. Much of the early advances in the operational aspects of GCS were learned from CO2-EOR. However, given its â€œnewnessâ€� and the health, safety, and environment (HSE) concerns related to CO2 emissions, considerable fundamental and applied research with heavily instrumented GCS field projects, from pilot to commercial scale, has produced data not ordinarily available from conventional CO2-EOR studies. A key exception is the Weyburn-Midale CO2-EOR project in Saskatchewan, Canada, which has had a dedicated characterization, reservoir dynamics and surveillance program in operation since 2000. Even though many of the processes and workflows for these two operations are similar, significant differences do exist primarily because of the different objectives and regulatory environments that exist for CO2-EOR and CO2 storage projects. Fundamentally, CO2 storage tools and processes are geared toward developing a much more detailed understanding of the storage system and the physical and chemical processes accompanying CO2 injection, with monitoring and surveillance being conducted during the pre-operational, operational, and post-operational stages of a project. Pre-operational monitoring for a CO2-EOR project is primarily focused on understanding the reservoir physical and petrophysical properties as well as the properties of the reservoir and injected fluids. Surveillance in the operational phase of an EOR flood is limited, with emphasis being placed on monitoring injection pressures and rates as well as the volumes and properties of the injected and produced fluids. Lessons learned from GCS research and field tests will likely benefit CO2-EOR project performance by employing aspects of characterization, simulation and surveillance. This study reviews the predictive and diagnostic tools currently applied to GCS projects and infers how their deployment might improve CO2-EOR projects. These improvements might include project conformance, CO2 utilization / oil produced, field management, and containment risks.
Light hydrocarbon and noble gas migration as an analogue for potential CO2 leakage: numerical simulations and field data from three hydrocarbon systems
(2019-01-16) Anderson, Jacob; Romanak, Katherine D.; Alfi, Masoud; Hovorka, Susan D.
Modeling CO2 Partitioning at a Carbonate CO2-EOR Site: Permian Basin Field SACROC Unit
(2018) Hosseininoosheri, Pooneh; Hosseini, Seyyed A.; Nunez-Lopez, Vanessa; Lake, L.W.
Potential evaluation of CO2 EOR and storage in oilfields of the Pearl River Mouth Basin, northern South China Sea
(2018) Li, P.; Liu, X.; Lu, J.; Zhou, D.; Hovorka, Susan D.; Hu, G.; Liang, X.
Potential of CO2-EOR for Near-Term Decarbonization
(2019-09-27) Nunez-Lopez, Vanessa; Moskal, Emily C.
Screening and simulation of offshore CO2-EOR and storage: A case study for the HZ21-1 oilfield in the Pearl River Mouth Basin, Northern South China Sea
(2019-07) Li, Pengchun; Yi, Linzi; Liu, Xueyan; Hu, Gang; Lu, Jiemin; Zhou, Di; Hovorka, Susan D.; Liang, Xi