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Collaborating Authors
Results
Recovery Potential and Mechanism Investigation of the Supercritical CO2 EOR in the Bakken Tight Formation
Wang, Sai (University of North Dakota) | Han, Juan (University of North Dakota) | Wang, Yanbo (University of North Dakota) | Ling, Kegang (University of North Dakota) | Jia, Bao (University of North Dakota) | Wang, Hongsheng (Virginia Tech) | Long, Yifu (Missouri University of Science and Technology)
Abstract The low recovery of oil from the tight liquid-rich formations is still a main challenge for the tight reservoir. Thus, in order to break the chains and remove the obstacle such as the low recovery factor in the Bakken tight formation, even though the horizontal drilling and hydraulic fracturing technologies were already well applied in this field, the supercritical CO2 flooding was proposed as an immense potential recovery method for the production improvement. In this research, we conducted a series of CO2 flooding experiments under various injection pressure (2500psi, 2800psi, 3000psi, 3500psi), to investigate the recovery potential of the core sample from Bakken tight formation. Also, the NMR analysis was processed of the core samples flooded with CO2 agent under the above injection pressure variables. The result comparison demonstrates that, with the supercritical CO2 injection pressure increase, the recovery factor gets incremental trend from 8.8% up to 33% recovery. Also, the macro pore and natural fracture system were proved to contribute more on the recovery potential. After reaching the miscible phase between the CO2 and oil in the sample, the hydrocarbon existed in the micro pores start the contribution to the recovery potential. Thus, The CO2 was identified as a potential recovery agent and the supercritical CO2 EOR method was proposed as the potential recovery technology due to the high recovery factor obtained in the immiscible and miscible processes.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.69)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation > Middle Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Three Forks Group Formation (0.97)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Carbon Dioxide Injection Pressure and Reservoir Temperature Impact on Oil Recovery from Unconventional Shale Reservoirs During Cyclic CO2 Injection: An Experimental Study
Fakher, Sherif (Missouri University of Science and Technology) | Ahdaya, Mohamed (Missouri University of Science and Technology) | Elturki, Mukhtar (Missouri University of Science and Technology) | Imqam, Abdulmohsin (Missouri University of Science and Technology)
Abstract Carbon dioxide (CO2) injection has recently been applied in unconventional shale reservoirs to increase oil recovery. There are many methods by which CO2 can be injected. One of the most common methods, especially in unconventional reservoirs, is cyclic CO2 injection. This research experimentally investigates the ability of cyclic CO2 injection to increase oil recovery from unconventional shale reservoir, and the impact of reservoir thermodynamics, including pressure and temperature, on the oil recovery potential. The experiments were conducted using a specially designed vessel to mimic the cyclic CO2 injection operation. The shale cores were saturated with crude oil for seven consecutive months at high temperature. The cores were then placed in the huff-n-puff vessel and the experiment was commenced. The pressure and temperature conditions were found to have a strong impact on oil recovery, especially as the injection cycles progressed. The thermodynamic conditions were also found to impact the core integrity greatly, with some cores breaking at some conditions, and the natural fractures being stimulated as well. This research can help illustrate the impact of reservoir thermodynamics on the oil recovery potential from unconventional shale reservoirs during cyclic CO2 injection.
- North America > United States > North Dakota (0.69)
- North America > United States > Montana (0.69)
- Research Report > Experimental Study (0.50)
- Research Report > New Finding (0.41)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline (1.00)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (5 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
ABSTRACT Tight gas reservoirs always have low natural gas recovery due to poor physical properties. However, there is still no effective means to enhance gas recovery (EGR) in tight gas reservoir. In this paper, experimental approaches were carried out to study the Supercritical CO2 (SCCO2) injection for EGR in tight gas reservoirs. Phase behavior investigation was performed to indicate the property difference between SCCO2 and natural gas under reservoir condition. Results show that SCCO2 has significantly higher density and viscosity than natural gas under reservoir condition. Gravity differentiation and near-piston displacement can be achieved in case of SCCO2 injection and thus the displacement efficiency can be improved. Gas adsorption tests show that the adsorption capacity of SCCO2 in tight sandstone is more than 50% higher than that of natural gas. Diffusion simulation show that SCCO2 shows weak diffusion capacity and slow diffusion process in natural gas, which indicates that SCCO2 and natural gas are not easy to mix and it is good for displacement and EGR. On the basis of these fundamental tests, long-core experiments of SCCO2 injection for EGR in tight gas reservoir were carried out using natural cores from DS tight gas reservoir. Results indicate that SCCO2 injection can improve gas recovery by 18.9% on the basis of gas depletion. Furthermore, the influencing factors of SCCO2 injection in tight cores were experimentally investigated. Results demonstrate that SCCO2 injection have better EGR effect in case of lower permeability, higher water saturation and greater dip angle.
- Asia > China (0.70)
- North America > United States (0.70)
- Research Report > New Finding (0.87)
- Research Report > Experimental Study (0.68)
- Geology > Geological Subdiscipline > Geomechanics (0.47)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.37)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
The Impact of Thermodynamic Conditions on CO2 Adsorption in Unconventional Shale Reservoirs Using the Volumetric Adsorption Method
Fakher, Sherif (Missouri University of Science and Technology) | Ahdaya, Mohamed (Missouri University of Science and Technology) | Elturki, Mukhtar (Missouri University of Science and Technology) | Imqam;, Abdulmohsin (Missouri University of Science and Technology)
Abstract Carbon dioxide (CO2) injection is an enhanced oil recovery method that can increase oil recovery from different types of oil reservoirs. It has been recently applied in unconventional shale reservoirs for both enhanced oil recovery and CO2 storage applications. This research explains the main mechanism of adsorption, which is the main force by which CO2 can be stored in shale reservoirs, and then performs an experimental study to investigate the factors impacting CO2 adsorption using the volumetric adsorption method. The review will cover the main definition of adsorption and how it can help in CO2 storage. It will also include the mathematical equations used to obtain adsorption for the volumetric adsorption method. The experimental study then investigates the impact of three major parameters including CO2 injection pressure, temperature, and shale volume on the adsorption capacity of the shale. The experimental results showed that the factors studies had a strong influence on the CO2 storage potential. Increasing the CO2 injection pressure increased the adsorption capacity, whereas increasing the temperature reduced the adsorption greatly. The shale volume strongly impacted the accuracy of the results obtained using the volumetric method and thus is an extremely important parameter in the design of adsorption experiments if the volumetric method is to be used. The parameters studied in this research should be accounted for when designing a CO2 enhanced oil recovery operation if CO2 storage is a part of the project.
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (8 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- (2 more...)
The Effect of Unconventional Oil Reservoirsโ Nano Pore Size on the Stability of Asphaltene During Carbon Dioxide Injection
Fakher, Sherif (Missouri University of Science and Technology) | Ahdaya, Mohamed (Missouri University of Science and Technology) | Elturki, Mukhtar (Missouri University of Science and Technology) | Imqam, Abdulmohsin (Missouri University of Science and Technology) | Elgahawy, Youssef (University of Calgary)
Abstract Carbon dioxide (CO2) has been proven to be an extremely successful enhanced oil recovery method to increase oil recovery from hydrocarbon reservoirs. It has also been proposed as a novel production method for unconventional shale reservoirs with nano pores as well. One of the main drawbacks of CO2 injection is asphaltene precipitation and deposition, which may result in severe pore plugging, and thus a significant decrease in oil recovery. Even though asphaltene precipitation during CO2 injection in conventional oil reservoirs has been researched extensively, not much research has been conducted to evaluate asphaltene precipitation and pore plugging in unconventional nano pores. This research investigates the impact of several factors on asphaltene precipitation and deposition, and asphaltene pore plugging in nano pores. Composite nano-filter membranes with 10, and 100 nm pore size were used to conduct all experiments. A specially designed high pressure high temperature filtration vessel was constructed and utilized to accommodate both the filter membrane, and the crude oil. The impact of varying the CO2 injection pressure, temperature, filter membrane pore size, and the CO2 soaking time on asphaltene deposition, and pore plugging were investigated. Results showed that higher CO2 injection pressures resulted in a higher oil recovery, a lower asphaltene concentration in the unproduced, bypassed oil, and a higher asphaltene concentration in the produced oil compared to the lower CO2 injection pressures. An opposite trend was observed with the temperature however, due to the temperature resulting a severe disturbance in the asphaltene thermodynamic equilibrium with the other crude oil components. Increasing the pore size resulted in a less severe asphaltene pore plugging, whereas increasing the CO2 soaking time resulted in an increase in the asphaltene deposition and pore plugging. This research performs an experimental study to show the main factors that will impact asphaltene precipitation, deposition, and pore plugging in nano pores during CO2 injection. This may help in improving oil recovery from CO2 injection projects in unconventional shale reservoirs, especially those with a high asphaltene percentage in their crude oils.
- North America > United States > Texas (0.29)
- Asia > Middle East > UAE > Abu Dhabi Emirate (0.28)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.91)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.57)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- (2 more...)
Abstract With the demand for conformance control in CO2 flooding fields, the traditional HPAM-Cr(III) polymer gel has been applied to reduce excess CO2 production. However, the field application results are mixed. In order to understand the HPAM-Cr(III) polymer gel plugging performance in reservoirs, a numerical reservoir analysis is used to interpret the laboratory results and analyze how the laboratory results are connected to the field application results. The HPAM-Cr(III) polymer gel plugging performance was evaluated in the laboratory with sandstone core plugs. CO2 and water effective permeability was measured. Gelant was injected into the cores until the injection pressure stabilized. Breakthrough pressure was tested and followed by two WAG cycles injection. The injection pressure was monitored. Different permeability cores (100- 1200 md) were used to mimic different reservoir conditions. Residual resistance factor was calculated using the stabilized water/CO2 injection pressure before and after gel treatment. HPAM-Cr(III) polymer gel has higher breakthrough pressure in the low permeability cores. The polymer gel behavior is discussed using three scenarios: no breakthrough, partial breakthrough, and breakthrough. If no breakthrough, the numerical reservoir analysis reveals that the polymer gel can successfully divert the CO2 and water flow to the low permeability layers before breakthrough. The damage to polymer gel is caused by CO2 diffusion from the low permeability layers. The gel damage rate depends on the diffusion rate. This is the reason that polymer gel treatment can last for a longer time in some fields. In the breakthrough scenario, CO2 totally breaks through the gel-treated zone, polymer gel has a larger contact area with CO2 and the gel damage rate will be faster. Therefore, the polymer gel has almost no blocking to CO2 flow.
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Study on Dynamic Phase Behavior of Oil and Gas System during CO2 Flooding
Xianhong, Tan (CNOOC Research Institute) | Kuiqian, Ma (CNOOC Tianjin Branch) | Shichao, Chai (CNOOC Tianjin Branch) | Xiaofeng, Tian (CNOOC Research Institute) | Nan, Li (CNOOC Research Institute) | Shiqiang, Peng (CNOOC Research Institute) | Na, Li (CNOOC Research Institute) | Wei, Zheng (CNOOC Research Institute) | Lijun, Zhang (CNOOC Research Institute) | Chen, Hao (China University of Petroleum, Beijing)
Abstract CO2 flooding is one of the most promising EOR methods. Due to the complicated compositional change during the displacement process, the effect of CO2 injection on phase behavior of oil and gas system is still not clear so far. It can great limits the forecast of development effect and composition optimization of injection gas. In this paper, taken an offshore oilfield of China as an example, based on compositional grouping, PVT test and slim tube test, phase behavior of oil and gas system during impure CO2 flooding was studied by PVT Sim 20. Results show that under reservoir conditions, the thickness of oil layer can greatly influence the composition distribution of the reservoir fluids. Thus, the phase behavior can be significantly different. For the initial stage of CO2 flooding, two-phase region of the phase diagram continuously extends. The cricondenbar increases obviously and the cricondentherm decreases. Critical point moves towards top left. With the CO2 flooding proceeding, the two-phase region begins to shrink when the gas oil ratio achieves 2:1. The cricondenbar increases slightly and the cricondentherm decreases significantly. Moreover, with the mixing of contaminated gases, the two-phase region enlarges and the cricondenbar increases greatly. However, the cricondentherm changes slightly. For pure CO2, the saturation pressures for different oil gas ratio are all lower than reservoir pressure, thus, it can achieve miscible flooding. Comparatively, for impure CO2, it becomes more and more difficult to fully miscible with oil. In sum, the CO2 displacement is the synthetic action of dissolution, dispersion, expansion, extraction, and viscosity reduction. Macroscopically, it is shown as the dynamic change of phase behavior of CO2-oil system.
- Asia > China (0.91)
- North America > United States > Texas (0.28)
- Research Report > New Finding (0.66)
- Research Report > Experimental Study (0.66)
- Asia > China > Jilin > Yanji Basin > Jilin Field (0.99)
- North America > United States > Louisiana > China Field (0.96)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Empirical Correlation of Minimum Miscible Pressure of Pure and Impure CO2 Flooding
Chen, Hao (China University of Petroleum, Beijing) | Li, Bowen (China University of Petroleum, Beijing) | Zhang, Xiansong (CNOOC Research Institute) | Tan, Xianhong (CNOOC Research Institute) | Tian, Xiaofeng (CNOOC Research Institute) | Han, Jingwen (China University of Petroleum, Beijing) | Yang, Shenglai (China University of Petroleum, Beijing)
Abstract Several methods to determine the MMP can be introduced for the forecast. Slim tube test is one of the widely accepted methods for the use of actual crude oil, but it is high cost and time consuming. The accuracy of slim tube simulation method greatly depends on the accuracy of compositional model matched by the PVT test data. Analytical method is very fast, but it is difficult to find the unique and correct set of key tie lines in the displacements is very difficult. This paper presents a simple and accurate empirical correlation for MMP prediction of miscible flooding, which is faster and less cumbersome than slim tube test and slim tube simulation. Unlike previous empirical correlation methods, our new correlation considers the effect of both reservoir temperature, oil composition and gas contamination, as well as the influencing degree. For pure CO2, except reservoir temperature, mole fractions of the (C1+N2), (C2โC4), and (C5โC6), molecular weight of C7of the crude oil are taken as the influencing factors for the MMP prediction. It is found that the relationship of MMP and these parameters is linearly dependent, thus, regress function based on least square method is used to fit a new correlation. On this basis, mole fractions of CH4, N2, H2S, and intermediate components (C2โC6) in the injection gases were separately selected to predict the MMP differences caused by the contaminated gas. Nlinfit function of nonlinear fitting was proposed due to the complex effect of reservoir temperature and volatile components of the oil on the mixing of oil and injection gases. Our approach is more accurate and robust than most of previous empirical correlations which lack specific consideration of the key factors. According our new empirical correlation, the MMP of miscible flooding for pure and impure CO2 can be calculated in minutes using by using a simple Excel spreadsheet with the input of just very basic data. Our approach supplies a more accurate method for the fast screening of potential oilfield to implement CO2 miscible flooding.
- Asia (0.94)
- North America > United States > Texas (0.68)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (0.89)
The Applicable Limits of the High Strength Gel System to the Tight Sandstone Fractured Reservoir in CO2 Flooding
Fenglan, Zhao (China University of Petroleum (Beijing)) | Ting, Xu (Sinopec Exploration and Development Research Institute) | Jirui, Hou (China University of Petroleum (Beijing) / Beijing Key Laboratory of Greenhouse Gas Sequestration and Oil Exploitation) | Liguang, Song (China University of Petroleum (Beijing) / Beijing Key Laboratory of Greenhouse Gas Sequestration and Oil Exploitation) | Guoyong, Lu (China University of Petroleum (Beijing) / Beijing Key Laboratory of Greenhouse Gas Sequestration and Oil Exploitation) | Hairu, Feng (China University of Petroleum (Beijing) / Beijing Key Laboratory of Greenhouse Gas Sequestration and Oil Exploitation)
Abstract The matrix permeability of the tight sandstone reservoir is very low, which causes difficulty to inject water, the CO2 flooding is applied widely to these reservoirs for the better oil displacement and low injection pressure, but natural fractures develop as well as artificial fractures exist in the tight reservoir, makes gas-channeling along the fractures severe when proceeding a CO2 flooding process, blocking the fractures is necessary for displacing the residual oil trapped in the matrix. The self-developed tight sandstone fractured cores which can simulate different conditions of fracture width and matrix permeability had been used to evaluate the blocking effect of the high strength starch gel system, the mechanism that the high strength gel system blocked the fractures and activated the residual oil in matrix was analyzed by comparing the pressure when CO2 broke through and the incremental recovery after blocking in CO2flooding experiments, then the applicable limits that the high strength starch gel system improved the oil displacement of CO2 flooding in the tight sandstone fractured reservoir had also been discussed. The results showed that the high strength starch gel system could be used to block the fractures, and the blocking effect and the incremental recovery were the best when the fracture width was 0.42mm, however both effects became worse when the fracture width decreased to 0.08mm or increased to 0.65mm because of the injection limitation or the reduction of blocking effect; furthermore, the residual oil in the matrix could be activated effectively after the high strength starch gel blocked the fractures even if the matrix permeability reduced to 0.1mD, the research results can provide reference to the design and optimization of project when proceeding a CO2 flooding process in the tight sandstone reservoir.
- Asia > China (1.00)
- North America (0.95)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
The Development of CO2 Plume in CO2 Sequestration in the Aquifer
Fu, Hao (University of North Dakota, Grand Forks) | Long, Yifu (Missouri University of Science and Technology) | Wang, Sai (University of North Dakota, Grand Forks) | Wang, Yanbo (University of North Dakota, Grand Forks) | Yu, Peng (Beibu Gulf University, Qinzhou) | Ling, Kegang (University of North Dakota, Grand Forks)
Abstract Geological carbon sequestration through injecting large-scale carbon dioxide (CO2) into the deep saline aquifers represents a long-term storage of CO2. In the CO2 sequestration process, the injected CO2 is displacing water from the injection point and is expected to remain in the reservoir. Due to the nature of one phase displacing another phase in porous media, it is noted that different water saturation exists in the CO2 plume during the displacement. Water distribution in the plume will affect the size of the plume subsurface. Furthermore, the gravitational segregation between CO2 and water will cause overriding-tonguing during the injection and impact the shape of plume. To better understand the CO2 movement underground and development of CO2 plume, it is necessary to take the two-phase flow and gravity force effects into account when evaluating CO2 displacing water. The displacement of water by injecting CO2 is not a piston-like process in aquifer. Because water is the wetting phase and CO2 is the non-wetting phase when two phases flow in reservoir, water occupies the surface of matrix and small pores while CO2 resides in large pores and centers of pores. As a result, various water saturations distribute behind CO2 front during the displacement. The distribution is a function of fluid and rock properties, fluid-rock interaction, and injection operation. In this study, these factors are considered when developing new models to predict CO2 plume evolution during injection. Mass conservation, multiphase flow, and equation-of-states are applied in the derivation of the models, which guarantees a rigorous approach in the investigation. The modeling results indicate that CO2 does not displace water completely away from the plume. The shape of the CO2 front is controlled by the relative permeability of two phases and capillary pressure. Water saturation profile from CO2 injecting point to the displacement front shows that water saturation behind the CO2 front increases outwardly, and the change in saturation is non-linear. The injection rate impacts the sharpness of the CO2 front, thus leads to different gas plume sizes for same injection volume. The outward movement of the CO2 front decelerates as injection time goes on. The research illustrates that injection experiences two stages: transient and steady-state, in which the displacement behavior and the development of gas plume vary. Although the duration of transient stage is dictated by size of aquifer and is relatively short comparing with steady-state stage, its influence on the development of CO2 plume cannot be neglected when selecting gas compressor horsepower and determining injection rate.
- Asia (0.68)
- North America > United States > Kansas (0.46)
- North America > United States > North Dakota (0.28)
- North America > United States > Kansas > Dickman Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Wabamun Formation (0.97)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- (2 more...)