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Collaborating Authors
Middle East
Research and Application of Horizontal Well Infill SAGD Development Technology for Super Heavy Oil Reservoirs
Tao, Liang (Oil and Gas Technology Research Institute Changqing Oilfield Company, Petrochina Company Limited) | Li, Geng (University of Missouri) | Li, Lingduo (PetroChina natural gas sales Guangdong company) | Shan, Jiangtao (PetroChina Xinjiang Oilfield Company)
Abstract In order to find effective replacement technology for ultra-heavy oil reservoirs at the late stage of horizontal well cyclic steam injection, pilot test on infill steam-assisted gravity drainage (SAGD) development has been carried out in Xinjiang Oilfield, China. In this study, a fine reservoir geological model was built by combining numerical reservoir simulation with the pilot test to analyze the development mechanism of infill SAGD, and optimize the location of the infill SAGD well group, the infill timing, and the timing of horizontal well turning into production well, as well as the operational parameters of the infill SAGD during start-up phase and production phase. Also, the adjustment techniques at each stage have been worked out. The research results show that the reasonable development technical parameters of the infill SAGD are: the SAGD steam injection well is 5m above the original horizontal well, and the infilling time is after 7 to 8 cycles of steam injection of the original horizontal well; after infilling, the original horizontal well is converted into production well after 2 cycles of steam injection; the bottom hole dryness of steam is greater than 85%, and the production/injection ratio is 1.22 and 1.23. The new technology is expected to increase the ultimate recovery factor by 30%-35%, and will have great reference significance for the development of similar super heavy oil reservoirs.
- Asia > Middle East > Israel > Southern District > Southern Levant Basin > Ratio Field (0.99)
- Asia > China > Xinjiang Uyghur Autonomous Region > Junggar Basin > Xingjiang Field > Lucaogou Formation (0.99)
- Asia > China > Shanxi > Ordos Basin > Changqing Field (0.99)
- (4 more...)
Feasibility Study of Gas Injection in Low Permeability Reservoirs of Changqing Oilfield
Tian, Ye (Colorado School of Mines) | Uzun, Ozan (Colorado School of Mines) | Shen, Yizi (Colorado School of Mines) | Lei, Zhengdong (Research Institute of Petroleum Exploration and Development, PetroChina) | Yuan, Jiangru (Research Institute of Petroleum Exploration and Development, PetroChina) | Chen, Jiaheng (Research Institute of Petroleum Exploration and Development, PetroChina) | Kazemi, Hossein (Colorado School of Mines) | Wu, Yu-Shu (Colorado School of Mines)
Abstract Changqing Oilfield is the largest petroleum-producing field in China and one-third of its oil production is attributed to the formations with permeability lower than 1 mD. The rapid oil rate decline and low recovery factor (RF) associated with those formations require additional IOR/EOR measures besides waterflood. Based on the promising results from recent gas injection pilots in North America, we investigated the feasibility of gas injection in the low permeability formation (Chang 63) of Changqing Oilfield. An eight-component fluid characterization, which fits both the constant composition expansion (CCE) test and separator test, was used in a numerical dual-porosity compositional model. A typical well pattern, composed of six vertical injectors and one horizontal producer, is selected for the modeling study. The input parameters, including relative permeability, fracture permeability, etc., were adjusted to achieve an acceptable history match of the production data. Huff-n-Puff using several gasesโlean gas (CH4), produced gas, rich gas (C2H6), and solvent (C3H8)โ were investigated and the results were compared with the current waterflood. The simulation results show that the richer the injected gas, the higher the oil production. C3H8 huff-n-puff achieved the best performance, increasing the cumulative oil production by a factor of 2.28 after 5 cycles, then followed by C2H6 as 1.34, produced gas as 1.08. CH4 alone demonstrated a lower recovery factor than waterflood, because its minimum miscibility pressure (MMP) is close to the maximum allowable injection pressure, i.e., the minimum horizontal stress. In addition, the horizontal producer was completed at the reservoir top and water injectors were placed at the bottom, which was originally designed to improve the waterflood by gravity segregation. Under such well placement design, the miscible oil bank, which forms at the injection front during vaporizing drive, will be displaced towards the reservoir bottom even out of the SRV, undermining the huff-n-puff performance. Injection with rich gas will be more compatible, as the miscible bank forms at the injection tail. Injecting produced gas enriched with C3H8 will hence achieve promising EOR performance. The simulation also shows that increasing injection pressure increases the recovery factor. The leaner composition of produced gas could be compensated by a higher injection pressure. The optimal injection duration and soaking time could also be obtained after sensitivity analysis. Another critical factor is the fracture network characterized by the dual-porosity model, as simulation with the single porosity model only shows minor improvement in RF even with C3H8. Our work confirmed the technical feasibility of injecting rich gas in the low permeability Chang 63 by compositional simulation. We also determined the key parameters for the operator to consider in the next phase of the project.
- Asia > China > Shaanxi Province (1.00)
- Asia > China > Gansu Province (1.00)
- Asia > China > Shanxi Province (0.92)
- (2 more...)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.48)
- 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)
- (11 more...)
Comprehensive Experimental Study of Huff-n-Puff Enhanced Oil Recovey in Eagle Ford: Key Parameters and Recovery Mechanism
Min, Byeungju (University of Oklahoma) | Mamoudou, Sidi (University of Oklahoma) | Dang, Son (University of Oklahoma) | Tinni, Ali (University of Oklahoma) | Sondergeld, Carl (University of Oklahoma) | Rai, Chandra (University of Oklahoma)
Abstract Huff-n-puff gas injection enhanced oil recovery has received increased attention especially in the unconventional plays like the Eagle Ford, where oil recovery is as low as 5 - 10%. An increase in 1% of recovery could realize a potential of 2.3 billion barrels of oil, which has an enormous economic value. Through a laboratory investigation of huff-n-puff conducted on preserved Eagle Ford samples; we evaluate different factors that can affect the recovery performance such as minimum miscibility pressure (MMP), surface area, soaking time, injection pressure, composition of injection gas and injection gas rate. In addition, different recovery mechanisms such as a vaporization (concentration gradient) and a miscible flowback (pressure gradient) were also investigated. Two sets of experiments were conducted utilizing a high-pressure chamber: one with Eagle Ford oil, providing MMP values using a VIT technique and vaporization test with different soaking times (2 days, 4 days, and 6 days). Another set of experiment were performed with preserved Eagle Ford samples. Different types of gas: carbon dioxide (CO2,) methane (C1), ethane (C2), C1:C2 (72:28) mixture, C1:C2 (95:5) mixture, and field gas were injected at various pressures from 1000 psi below MMP, MMP to 1000 psi above MMP with various soaking time of (1 hr, 3 hr and 6 hr). Nuclear Magnetic Resonance (NMR), HAWK pyrolysis, isothermal nitrogen adsorption tests (BET), Mercury Injection Capillary Pressure (MICP) and Gas Chromatography (GC), were performed to qualitatively and quantitively monitor the changes in Eagle Ford hydrocarbons recovered from shale samples. The experimental results demonstrated that: 1) as methane concentration in gas is increased, MMP also increased, 2) residence time (soaking time + production time) controls the recovery, 3) injection pressure determines the fraction of hydrocarbons mobilized, 4) surface area variation studies showed that the samples with higher surface area have greater recoveries, 5) ethane showed the best performance of all the gases tested (40% recovery). CO2 performed the second best (32%). C1:C2(72:28) mixture and field gas exhibit the similar efficacy in recovery (24% and 21%). C1:C2(95:5) mixture showed the worst recovery (11%). 6) high injection rate yielded better recovery (37%) than low injection rate (24%), 6) Increase in pore surface area by factor of 2.5 was observed from the opening of small pores and pore- throat on post huff-n-puff sample. In addition, recovery mechanism study shows that miscible flow back mobilized hydrocarbon up to C30, vaporization at 1000psi above MMP mobilized hydrocarbon up to C23 and vaporization 1000psi below MMP mobilized hydrocarbon up to C15. The results also indicated that longer soaking times increased diffused oil concentration in vapor phase.
- North America > Canada (0.95)
- North America > United States > Texas (0.68)
- Research Report > Experimental Study (0.90)
- Research Report > New Finding (0.84)
- Geology > Geological Subdiscipline > Geochemistry (0.87)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.37)
- 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)
- (4 more...)
Abstract Steam injectionโa thermal-based enhanced oil recovery (EOR) processโis used to improve fluid mobility within a reservoir, and it is well known that it yields positive results in heavy-oil reservoirs. In theory, steam injection has the potential of being applied in light-oil reservoirs to enable vaporization of in-situ reservoir fluids, but field developments and scientific studies of this application are sparse. Conventional displacement methods like water-flooding and gas-flooding have been applied to some extent, however, oil extraction in such reservoirs relies on recovery mechanisms like capillary imbibition or gravity drainage to recover oil from the reservoir matrix. Furthermore, low-permeability reservoir rocks are associated with low gravity drainage and high residual oil saturation. The objective of this study is to evaluate the potential of steam injection for light (47ยฐAPI) oil extraction in naturally-fractured reservoirs. It is theorized that this method will serve as an effective tool for recovery of light hydrocarbons through naturally-fractured networks with the benefit of heat conduction through the rock matrix. This research investigates the application of light-oil steamflood (LOSF) in naturally- fractured reservoirs (NFR). A simulation model comprised of a matrix block surrounded by fracture network was used to study oil recovery potential under steam injection. To simulate gravity drainage, steam was injected through a horizontal well completed in the upper section of the fracture network, while the production well was completed at the bottom of the fracture network. The simulation included two different porous media: (1) natural fractures and (2) matrix blocks. Each of these porous media was assumed to be homogeneous and characterized based on typical reservoir properties for carbonate formations. This study also analyzed the impact of different recovery mechanisms during steam injection for a light-oil sample in NFR, with reservoir sensitivity examined, based on varying amounts of vaporization, injection rate, permeability, matrix height and capillary pressure. Of these, vaporization was found to be the dominant factor in the application of LOSF in NFR, as described in detail within the results.
- Asia > Middle East (0.94)
- North America > United States > Oklahoma (0.47)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.86)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.71)
- 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)
- (8 more...)
Abstract This paper presents the basic reservoir characteristics and the key improved oil recovery/enhanced oil recovery (IOR/EOR) methods for sandstone reservoir fields that have achieved recovery factors toward 70%. The study is based on a global analog knowledge base and associated analytical tools. The knowledge base contains both static (STOIIP, primary and ultimate recovery factors, reservoir/fluid properties, well spacing, drive mechanism, and IOR/EOR methods etc.) and dynamic data (oil rate, water-cut, and GOR, etc.) for more than 730 sandstone oil reservoirs. These reservoirs were subdivided into two groups: heavy and conventional oil reservoirs. This study focuses on the reservoirs with recovery factors great than 50% for heavy oil, and recovery factors from 60% to 79% for conventional oil with a view to understand the key factors for such a high recovery efficiency. These key factors include reservoir and fluid properties, wettability, development strategies and the IOR/EOR methods. The high ultimate recovery factors for heavy oil reservoirs are attributed to excellent reservoir properties, horizontal well application, high efficiency of cyclic steam stimulating (CSS) and steam flood, and very tight well spacing (P50 value of 4 acres, as close as 0.25 acres) development strategy. The 51 high recovery conventional clastic reservoirs are characterized by favorable reservoir and fluid properties, water-wet or mixed-wet wettability, high net to gross ratio, and strong natural aquifer drive mechanism. Infill drilling and water flood led to an incremental recovery of 20% to 50%. EOR technologies, such as CO2 miscible and polymer flood, led to an incremental recovery of 8% to 15%. Homogeneous sandstone reservoirs with a good lateral correlation can reach 79% final recovery through water flood and adoption of close well spacing. The lessons learned and best practices from the global analog reservoir knowledge base can be used to identify opportunities for reserve growth of mature fields. With favorable reservoir conditions, it is feasible to move final recovery factor toward 70% through integrating good reservoir management practices with the appropriate IOR/EOR technology.
- Asia > Middle East (1.00)
- Europe (0.93)
- North America > United States > Texas (0.50)
- North America > United States > Texas > East Texas Salt Basin > East Texas Field > Woodbine Formation (0.99)
- North America > United States > California > San Joaquin Basin > Kern River Field (0.99)
- Asia > Middle East > Oman > Al Wusta Governorate > South Oman Salt Basin > Mukhaizna Field (0.99)
- (3 more...)