Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Bai, Baojun
Optimizing Injector-Producer Spacing for CO2 Injection in Unconventional Reservoirs of North America
Alfarge, Dheiaa (Iraqi Ministry of Oil, Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology) | Almansour, Abdullah (King Abdulaziz City for Science and Technology)
Abstract Shale oil reservoirs such as Bakken, Niobrara, and Eagle Ford have become the main target for oil and gas investors as conventional formations started to deplet and diminish in number. These reservoirs have a huge oil potential; however, the predicted primary oil recovery is still low as average of 7.5 %. Carbon dioxide (CO2) flooding has been a controversial approach to increase oil recovery in these poor-quality formations. This study investigated the effect of injector-producer spacing, in range of 925-1664 ft, on CO2 performance in these plays by using numerical simulation methods. CO2 utilization value under differrent injector-producer spaces has been calculated. Increments in oil production rate, cumulative oil, and oil recovery factor have been determined in 1, 5, 10 years of CO2-flooding start-point. In this study, unfractured horizontal injectors are modeled to avoid conformance problems in natural fractured unconventional formations. Furthermore, the physical behavior for CO2 flooding under different conditions has been discussed. Finally, simulation results were analyzed and compared with some of pilot tests which had been conducted in North Dakota and Southeast Saskatchewan. The results indicated that CO2 flooding performance would be more pronounced, by increasing oil production rate and oil recovery factor, as the injector-producer spacing minimized. However, CO2 utilization value is significant high when the injector-producer spacing is very short due to depleted volume closeness. Interestingly, CO2 utilization value for all spacing scenarios would gradually be reduced with flooding time. This reduction in the injected-gas utilization-value has been matched with the pilot test which performed in southeast Saskatchewan. In addition, CO2 efficiency indicator is generally in range of 4.85-44.5 Mscf/STB in these unconventional reservoirs which is relatively high as compared with conventional reservoirs. These results have been confirmed by a good match which has been obtained between simulation results and some of pilotsโ performance. This paper provides a thorough idea about how to optimize the injector-producer spacing for CO2 flooding in these complex plays. Also, this work explains that CO2 efficiency indicator is different in these unconventional formations as in conventional reservoirs.
- Asia > Middle East (0.93)
- North America > Canada > Saskatchewan (0.88)
- North America > United States > North Dakota > Mountrail County (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.70)
- Geology > Geological Subdiscipline (0.68)
- 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 > North Dakota > Sanish Field > Bakken Shale Formation (0.99)
- (3 more...)
Abstract Unconventional resources have played a significant role in changing oil industry plans recently. Shale formations in North America have huge oil in place, 900 Billion barrels of recoverable oil in Bakken only. However, the predicted primary recovery is still low as less than 10%. Therefore, seeking for improved oil techniques to increase oil recovery in these complex plays is inevitable. In this paper, three stages of review have been combined to find out the applicability of the most feasible IOR methods in these unconventional reservoirs. Firstly, the most common fluid and rock properties of these reservoirs have been investigated and extensively discussed. Secondly, a comprehensive review has been conducted on most of published experimental studies, simulation works, and pilot tests which were performed to examine the applicability of different IOR methods in these unconventional plays. Finally, the performance of different IOR methods in pilots tests have been compared with experimental and simulation observations. These comparisons between field scale approaches (Pilot tests) and lab experiments have been used to diagnose the gap beween what had been reported from lab works and what happened in the field tests. This study found the integration method of different tools such as experimental, simulation, and pilot tests is the proper technique to accurately diagnose the most feasible IOR methods in these poor-quality reservoirs. This research found that CO2, surfactant, and natural gas are the most applicable IOR methods in these unconventional reservoirs. CO2 injection seems the most feasible technique among the reported IOR methods. However, this study found that there is a clear gap between lab-works conclusions and pilot tests performance. This gap mainly happened due to the misleading predicting for that diffusion mechanism would be the most dominant mechanism for CO2 in field conditions due to the pre-reported lab observations. However, pilot tests performance generaly denied any significant role for diffusion mechanisim on CO2 performance. Furthermore, although pilot tests indicated that injectivity problem is not a big obstacle in these unconventional reservoirs, most of the evidences explained that the improvement in the observed injectivity was due to Injection Induced Fractures (IIF) which are the main reason for conformance problems which happened in the reported pilot tests. The slow imbibition rate of surfacatant methods in these types of reservoirs might impair their potentinal success. Pilot tests apparently approved success of natural gas due its high compressibility and avialbility in these fields. Finally, this work specifies the most common problems which could face the most potentional unconventional IOR methods in field applications. Also, this study recommended new directions to be considered for fututure investigations on applicability of some IOR methods in these plays since they are more complex and very different from conventional formations.
- North America > United States > Texas (1.00)
- North America > United States > Montana (1.00)
- North America > Canada > Saskatchewan (0.94)
- (3 more...)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play (1.00)
- Geology > Geological Subdiscipline (1.00)
Summary Miscibility is not reached in carbon dioxide (CO2) flooding for recovery of heavy oils. Thus, an important advantage of no gas/oil surface tension is lost. Nevertheless, some CO2 continues to dissolve in oil and reduces the oil viscosity, which makes the displacement easier. This is an asset that remains. However, the viscosity of heavy crude is much higher than the viscosity of CO2, causing the displacement process to be unstable and leading to fingering or channeling. We have undertaken the linear-stability analysis of the displacement process, which is that of immiscible displacement but includes mass-transfer effects. All stabilizing/destabilizing mechanisms of both immiscible displacement and miscible displacement are included. A number of stabilizing mechanisms related to mass transfer have been identified. We are able to provide a numerical evaluation of the results that show the lowering of viscosity that is considered only in miscible displacement leads to a partial stabilizing effect that overcomes a large destabilizing effect of the adverse mobility ratio. There is a restricted form of instability that would only give rise to a mushy zone at the front. The two regions are separated at a wavenumber determined numerically as 0.531โcm. We are also able to show that in the limit that the solubility of CO2 in oil drops to zero, the above window of instability becomes infinite.
- Asia (1.00)
- North America > United States > Missouri (0.46)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (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)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Technical and Economic Evaluation of EOR Technology in Low-Oil-Price Period a New Polymerflooding Case Study From China
Wu, Xingcai (Research Inst. of Petroleum E&D, CNPC) | Zhang, Jichang (Liaohe Oilfield Company, CNPC) | Liang, Wuquan (Liaohe Oilfield Company, CNPC) | Xu, Hanbing (RIPED) | Wang, Qiang (LOC) | Xiong, Chunming (RIPED) | Ren, Tieying (LOC) | Zhang, Liang (LOC) | Bai, Baojun (Missouri University of Science and Technology) | Ye, Yinzhu (RIPED) | Tian, Xiaoyan (Startwell Energy Co. Ltd)
Abstract It is generally thought that EOR technology costs much, so the budget for EOR in low oil price period is inhibited. For further recogonize the issue, the paper conducted a follow-up technical and economic evaluation for a EOR project of high water cut mature oil field. LHSC is a multiple layer high pour point reservoir with severe uneven sweeping problem. The water cut is up to 95.3%. The new polymerflooding (NPF) application area is composed of 10 injection wells and 21 production wells. The injection anount was designed as 0.3 PV, and it was composed of the main slug of a novel paticle type polymer SMG and the pre slug of volume swellable particle PPG carried by polymer weak gel. During the injection process, the slug parameteres such as SMG diameter were adjusted. The numerical simulation model and economic analysis model were built up. The technical and economical competency of the project evaluated under different oil price. From December 21, 2010 to December 31, 2016, the total EOR slug injection amount was 0.29 PV. Among the 21 producers, 19 producers obtained good effect of oil rate increase and water cut decrease. The daily oil rate was increased from 27.0 t to 58.5 t for the highest, and the water cut was decreased from 95.3% to 91.1%. The cumulative oil incremental was 3.2ร10t. Numerical simulation results showed that by the end of the project, the cumulative oil incremental would be 4.35ร10t, and the recovery incremental would be 4.9%. Based on the actual oil selling price of each year, the input to output ratio was calculated as 1:3.1, and the EOR cost of one barrel oil produced was 21.5 USD, while the cost of one barrel oil produced in waterflooding is 52.1 USD. Under 30 USD/bbl oil price, the input to output ratio is 1:1.4. The results show that the NPF project has good technical and economic effect, and even under extreme low oil price, it still has economic feasibility. For the developed mature oil fields, the geological and development recognition is certain, and there are complete facility contruction. Under low oil price condition, it is obviously more economical to use novel efficient EOR technologies.The opinion of the paper may provide some reference for oil companies to make investment decision in low oil price period.
- Asia > China > Liaoning > Bohai Basin > Liaohe Basin > Liaohe Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Nitrogen Gas Flooding for Naturally Fractured Carbonate Reservoir: Visualisation Experiment and Numerical Simulation
Song, Zhaojie (China University of Petroleum) | Hou, Jirui (China University of Petroleum) | Liu, Zhongchun (Sinopec Petroleum Exploration and Production Research Institute & Sinopec Key Laboratory of Marine Oil & Gas Reservoir Production) | Zhao, Fenglan (China University of Petroleum) | Huang, Shijun (China University of Petroleum) | Wang, Yong (China University of Petroleum) | Wu, Jieheng (China University of Petroleum) | Bai, Baojun (Missouri University of Science and Technology)
Abstract Tahe Naturally Fractured Carbonate Reservoir has implemented nitrogen gas flooding since 2013, with daily oil production of 7580 bbls and oil recovery increment of 0.83% by the end of 2015. However, the presence of fractures significantly affects gas swept volume and production performance, so large amount of oil reserves is poorly flooded due to gas channeling through fractures. The fluid flow mechanisms in fractured models were discussed in order to improve field gas flooding efficiency. Based on the geological constrains of Tahe Oilfield, fractured models with different apertures were fabricated using acrylic glass to model carbonate matrix wettability and for a better observation on fluid flow behavior. The models were placed vertically and horizontally to simulate the high-angle and low-angle fractures in the formation. Gas displacing oil experiments were performed at different injection velocities. The oil displacement characteristics were depicted and the production performance was recorded and discussed. Experimental data were history matched through numerical simulation, and thus a sensitivity study was conducted via design of experiments. For downward gas injection in the high-angle fractured model with a given aperture, a critical injection velocity was obtained below which piston-like displacement was observed. Channeling factor was defined to characterize the injected gas channeling features. It gradually increased and reached its maximum value with increasing injection velocities. The relationship between channeling factor and injection velocity was well fitted by Langmuir equation, and the mechanism behind it was elucidated. Based on their relationship, three gas/oil flow regions were illustrated including non-channeling, transitional channeling, and stable channeling. For all fractured models, the critical injection velocity increased and the maximum channeling factor declined with the increase of fracture aperture. A standard curve was plotted, which enables us to determine different flow regions according to the fracture aperture and injection velocity. For oil displacement in the low-angle fractured models, the top part was flooded at a specific range of injection velocity. Gravity effect was weakened and the middle part was flooded at relatively high injection velocities. Numerical fractured models were built and thus calibrated by history matching all the experimental data at different fracture apertures and injection velocities. A sensitivity study was conducted and the weighting of different variables was emphasized via DOE. Previous studies were mostly focused on gas flooding efficiency in naturally fractured carbonate reservoirs; however, this study visually depicted the gas-oil flow behavior through lab experiments, and demonstrated the weighting of different variables via numerical simulation using DOE. This paper could provide an insight into field gas injection projects and the development of the commercial numerical simulator that is specialized for naturally fractured carbonate reservoirs.
- North America > United States > Mississippi > Marion County (0.24)
- Asia > China > Xinjiang Uyghur Autonomous Region (0.24)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
Evaluation of Preformed Particle Gels Penetration into Matrix for a Conformance Control Treatment in Partially Open Conduits
Imqam, Abdulmohsin (Missouri University of Science and Technology) | Aldalfag, Ahmed (Missouri University of Science and Technology) | Wang, Yanling (China University of Petroleum) | Bai, Baojun (Missouri University of Science and Technology)
Abstract Preformed particle gels (PPGs) serve as a conformance control agent and have been used widely to control excess water production through conduits, fractures or fracture-like features. This paper ranks the parameters that impact PPG resistance to water flow in partially opened conduits and provides methods to minimize PPG penetration effect on matrices. Experiments were conducted to examine the effect of brine concentration, PPG injection pressure, back pressure, and matrix permeability on PPG resistance to water flow through conduits and PPG penetration to matrix. PPGs were swelled in different concentration brines and were injected into the conduits at a few designed injection pressures. Results show PPG resistance to water flow may have been the result of gel particle accumulation into conduits or gel filter cake formation in rock matrix or both. Their resistance increased when they were injected at high pressure. In contrast to PPGs placement through fully opened conduits, PPGs were not produced from the partially opened conduits; however, PPGs formed a filter cake on the surface of the matrix. Gel particles penetration into the matrix were only a few millimeters deep, and their penetration into to the matrix depended on matrix permeability, gel strength, and injection pressure drop across the core.
- North America > United States (1.00)
- Asia (1.00)
Use of Hydrochloric Acid To Remove Filter-Cake Damage From Preformed Particle Gel During Conformance-Control Treatments
Imqam, Abdulmohsin (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Elue, Hilary (Missouri University of Science and Technology) | Muhammed, Farag A. (Missouri University of Science and Technology)
Summary Millimeter-sized (10-ยตm to mm) preformed particle gel (PPG) has been used to control water flow through superhigh-permeability zones and fracture zones in mature oil fields. When the PPG is extruded into target zones, the gel can form a cake on the surface of low-permeability, unswept formations. This cake reduces the effectiveness of conformance control and the amount of oil that can be recovered from unswept oil formations. Thus, this study evaluated the effectiveness of using hydrochloric acid (HCl) to remove gel cakes induced during conformance-control treatments. The interactions between HCl and PPG were evaluated to understand the swelling, deswelling, and gel strength after adding acid. A Hassler core holder was then used to determine the core permeability after gel and acid treatments. Gels swollen in brine concentrations of 0.05, 1, and 10% were injected into a sandstone core having a variety of permeabilities. Brine was then injected in cycles through the gel into the core. The core permeability was measured after the gel-particle injection and after the core surface of the gel cake was soaked in the acid solution for 12 hours. The results indicate that particles swollen in brine concentrations of 0.05% caused more damage than those swollen in higher concentrations of brine. The damage increased as the core permeability increased for all the swollen gels. HCl removed the gel cake effectively; varying the HCl concentration did not cause a significant difference in the gel-cake removal efficiency. The gel was found to swell much less in HCl solutions than in brine. After the gel was deswollen in acid, the gel strengths were found to be higher than when the gel was swollen in brine. This work concludes that HCl can be used effectively to mitigate the damage induced by PPGs.
- Europe (0.67)
- Africa (0.67)
- North America > United States > California (0.46)
- Geology > Mineral (0.68)
- Geology > Geological Subdiscipline (0.67)
- Geology > Rock Type > Sedimentary Rock (0.34)
- North America > United States > California > Ventura Basin > Sockeye Field (0.99)
- North America > United States > California > Monterey Formation (0.99)
- Asia > China > Henan > Weicheng Field (0.94)
- Asia > China > Henan > Mazhai Field (0.94)
A Single Pore Model for Displacement of Heavy Crude Oil With Carbon Dioxide
Tran, Truynh Quoc (Department of Chemical and Biological Engineering) | Ahmad, Mohammed Almabrouk (Department of Chemical and Biological Engineering) | Neogi, P.. (Department of Chemical and Biological Engineering) | Bai, Baojun (Department of Geological Science and Engineering, Missouri University of Science and Technology)
Summary The present problem analyzes displacement of heavy crude oil in a capillary by carbon dioxide (CO2) as seen in enhanced oil recovery (EOR). In immiscible displacement of viscous liquid in a tube by a gas with lower viscosity than the liquid, a gas bubble moves steadily and leaves behind a thin liquid film of thickness hโ which is known as the Bretherton problem. With the recovery of crude oil in mind, the analysis was confined to cylindrical pores of diameter โ1โยตm, and hence disjoining pressures are included and added to the Laplace pressures. It is observed that, at small capillary numbers, the effect of disjoining pressure dominates, and at large capillary numbers, the Laplace pressure dominates. The key contribution here is the solutions to the mass-transfer problem in the form of CO2 dissolving in oil. We included the changes of the physical properties of heavy crude oil on carbonation on the basis of a real system. The thickness of thin residual oil film decreases in the presence of mass transfer, leading to an increase in oil recovery, but lowers the carbonation because of the convection in the reverse direction. The opposite is true of displacements at low capillary numbers in which the disjoining pressure dominates. The numerical solutions were obtained with ANSYS FLUENT software for the profile shapes, capillary numbers, the thicknesses of thin oil films left behind, and the net mass-transfer rates. The capillary pressure dominates the net pressure drop that one can lower by lowering the surface tension.
Experimental and Simulation Study of Water Shutoff in Fractured Systems Using Microgels
Goudarzi, Ali (The University of Texas at Austin) | Alhuraishawy, Ali (Missouri University of Science and Technology) | Taksaudom, Pongpak (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin) | Bai, Baojun (Missouri University of Science and Technology) | Imqam, Abdulmohsin (Missouri University of Science and Technology) | Delshad, Mojdeh (The University of Texas at Austin)
Abstract Conformance control has long been a compelling subject in improving waterflood oil recovery. By blocking the areas previously swept by water, subsequently injected water is allowed to access the remaining unswept portions of the reservoir and thereby increase the ultimate oil recovery. One technique that has recently received a great deal of attention in achieving the so-called "in-depth water shut-off' is preformed gel injection. However, processing and predicting the performance of these gels in complex petroleum reservoirs is extremely challenging. As target reservoirs for gel treatments are mainly those with fractures or ultra-high permeability streaks, the ability to model the propagation of gels through a fractured reservoir was considered as a new challenge for this research study. The primary objectives of this work are to conduct laboratory work to understand the transport and propagation of microgel through fractures and develop conformance control schemes using a reservoir simulator to help in screening oil reservoir targets for effective particle gel applications to improve sweep efficiency and reduce the water production. Fractured experiments using transparent apparatus were performed to observe gel transport in matrix and fractures. The same set up was used to observe the effects of gel strength, gel particle size, and fracture size on gel transport. Numerical simulation of fluid-flow in fractured reservoirs can be computationally difficult and time consuming due to the large contrast between matrix and fracture permeabilities and the extremely small fracture apertures and the need for using unstructured gridding. In this work, a model that accurately represents the complex reservoir features, chemical properties, and displacement mechanisms is developed. The five-spot transparent fracture experiments allowed us to identify the transport mechanisms of microgels through fractures-conduits and also the control variables. With an integration of comprehensive gel transport modules and a novel Embedded Discrete Fracture Modeling (EDFM), gel rheological and transport properties of shear thinning viscosity, adsorption, resistance factors, and residual resistance factor, using multiple sets of fractures with dip angles and orientations were captured. The models were validated against lab measurements and implemented into a reservoir simulator called UTGEL. The mechanistic models and numerical tool developed will help to select future conformance control candidates for a given field and to optimize the gel chemistry and treatment.
- North America > United States > Texas (0.70)
- Asia > Middle East (0.68)
Coupling Low Salinity Water Flooding and Preformed Particle Gel to Enhance Oil Recovery for Fractured Carbonate Reservoirs
Alhuraishawy, Ali K. (Missouri University of Science and Technology, Missan Oil Company) | Imqam, Abdulmohsin (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology)
Abstract The recovery of oil from carbonate reservoirs is usually low due to their extreme heterogeneity caused by natural fractures and the nature of the oil-wet matrix. Low salinity water flooding (LSWF) and preformed particle gels (PPGs) control conformance are two novel technologies that have recently drawn great interest by the oil industry. We developed a cost- effective, novel, enhanced oil recovery (EOR) technology for carbonate reservoirs by coupling the two technologies into one process. The objective of this paper is to provide a comprehensive understanding of the combined technology and to test through laboratory experiments the extent to which the coupling method can improve oil recovery. The laboratory experiments showed that the optimum water salinity for the application of the coupled method was 0.1 wt. % NaCl under experimental conditions. The water residual resistance factor (Frrw) increased as the water salinity and the fracture width decreased. The oil- wet carbonate cores provided a higher improved oil recovery than a water-wet carbonate cores during LSWF. The decrease in fracture width resulted in a higher oil recovery factor. Compared to traditional bulk gel treatments, PPG forms stronger plugging but will not form an impermeable cake in the fracture surface; therefore, PPG allows low salinity water to penetrate into the matrix to modify its wettability, thus producing more oil from the matrix. Results also show that oil recovery increased by 10 % during LSWF after the second waterflooding. Additionally, when PPG was injected, another 8 % of oil recovery was gained. As a result, combined the LSWF and PPG increased oil recovery by 18%. LSWF can increase only displacement efficiency but has little or no effect on sweep efficiency, while particle gels can plug fractures or in high-permeable channels to improve sweep efficiency but have little effect on displacement efficiency. The coupled method bypasses the limitations of each method when used individually and improve both the displacement and the sweep efficiency.
- Geology > Rock Type > Sedimentary Rock (0.70)
- Geology > Mineral (0.46)
- Geology > Petroleum Play Type > Unconventional Play > Fractured Carbonate Reservoir Play (0.40)