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01 August 2022, Volume 43 Issue 4 Previous Issue    Next Issue

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OIL AND GAS EXPLORATION

Characteristics and Formation Mechanism of Traps in K1g1 Reservoir in Changshaling Structural Zone, Jiuquan Basin WEI Jun, YAN Baonian, DU Wenbo, ZHOU Xiaofeng, ZHOU Zaihua, LI Tiefeng, XIE Jingyu 2022, 43 (4):  379-386.  doi: 10.7657/XJPG20220401 Abstract ( 311 )   HTML ( 21 )   PDF (7073KB) ( 147 )   Save With the meanings such as core observation, casting thin section identification and scanning electron microscope imaging, and based on the analysis of sandstone in light of petrological characteristics, diagenesis, pore types and dissolution fluid sources, the trap formation mechanism was investigated. The results show that the traps in the sandstone reservoir of the first member of the Cretaceous Xiagou formation (K1g1) in the Changshaling structural zone, Jiuquan basin, are diagenetic traps, the reservoir space is dominated by secondary pores, and the barrier is tight sandstone cemented by calcite in the early diagenetic stage. Atmospheric fresh water carrying smectite particles infiltrates through faults and dissolves the calcite cements and feldspar particles in tight sandstone, creating secondary intergranular pores and intragranular pores and clay-rich reservoir forms. The tight sandstone which is far from faults and has non-contact with atmospheric fresh water becomes the barrier. The traps are elongated and distributed along the fault trend, with the characteristics of “large sand bodies and small traps”. For the K1g1 sandstone reservoir, the diagenetic traps controlled by faults should be preferentially explored and wells should be deployed in the areas close to faults. Figures and Tables | References | Related Articles | Metrics

Characteristics and Genesis of Condensate Reservoirs of Lianggaoshan Formation in Fuling Area, Southeastern Sichuan Basin LI Mingyang, LI Chengyin, QU Dapeng 2022, 43 (4):  387-395.  doi: 10.7657/XJPG20220402 Abstract ( 301 )   HTML ( 14 )   PDF (1211KB) ( 159 )   Save In the condensate gas reservoirs of the Lower Jurassic Lianggaoshan formation in the Fuling area, southeastern Sichuan basin, the fluid properties are complex and the gas-oil ratios from multi-well testing differ greatly. In this paper, the basic characteristics of oil and gas were clarified by using the data such as crude oil chromatography-mass spectrometry, gas composition, carbon isotopes and fluid inclusions. The gas reservoir properties and phase states were determined with the empirical calculation method for gas compositions and through the experiments simulating PVT fluid phase state. On this basis, the genesis and forming process of condensate gas reservoirs were discussed. The results show that the gas reservoirs in the Lianggaoshan formation are mainly condensate gas reservoirs without oil rings, where hydrocarbons are mainly primary condensate oil and gas generated from Type Ⅱ2 kerogens in the mature stage, and cracking gas is found locally. The thermal evolution degree of source rocks and the differences in the present temperature and pressure conditions of formation are the main contributors to different reservoir properties. The superimposed areas of the relatively deep-burial areas during the hydrocarbon accumulation period on the areas with relatively high pressure at present are favorable targets for future exploration. Figures and Tables | References | Related Articles | Metrics

Sedimentary System of Permian Fengcheng Formation in Hashan Area in Northwestern Margin of Junggar Basin YU Hongzhou, WANG Yue, ZHOU Jian, XUE Yan 2022, 43 (4):  396-403.  doi: 10.7657/XJPG20220403 Abstract ( 313 )   HTML ( 13 )   PDF (12519KB) ( 136 )   Save The Fengcheng formation in the Hashan area in the northwestern margin of Junggar basin experienced strong tectonic deformation and structural displacement. There are few studies on the sedimentary system of the Fengcheng formation, which restricts the oil and gas exploration in this area. The 3D seismic, drilling, logging and core data in the Hashan area were systematically analyzed, and the structural evolution of the Fengcheng formation in different parts of the Hashan area was investigated, so that the original stratigraphic position of the Fengcheng formation was restored, the sedimentary facies types were analyzed and compared, and finally the original sedimentary system of the Fengcheng formation in this area was restored. The results show that in the Hashan area the tectonic compression strength gradually weakens from west to east, and the shortened distances of the Lower Permian from the Early Permian to the present in the western, central and eastern parts due to the compression are 33.0-40.0 km, 25.0-30.0 km and 15.0-20.0 km, respectively. Three types of sedimentary facies such as fan delta, beach bar and lake are developed and volcanic rocks of a certain scale are found in the Fengcheng formation. During the deposition of Feng 1 member, large-scale fan deltas and shore-shallow lakes were developed in the northern part of the Hashan area, semi-deep to deep lakes and beach bars in a small range in the central-western part, and volcanic rocks in the central-eastern part. During the deposition of Feng 2 member, the sedimentary range of semi-deep to deep lakes expanded significantly, thick layers of dolomitic mudstone was developed, and the distribution range of fan-delta sandy conglomerate and volcanic rocks decreased. During the deposition of Feng 3 member, the provenance supply capacity was enhanced, large-scale contiguous fan-delta sandy conglomerate was developed in the northern and western parts and semi-deep to deep lakes and beach bars were found locally. Figures and Tables | References | Related Articles | Metrics

Genesis of Calcareous Sandy Conglomerate of Baikouquan Formation in Well XIA72 Fault Block, Mabei Oilfield WU Shunwei, XIA Xueling, ZHU Shijie 2022, 43 (4):  404-409.  doi: 10.7657/XJPG20220404 Abstract ( 239 )   HTML ( 4 )   PDF (1627KB) ( 140 )   Save Calcareous sandy conglomerate was encountered in multiple wells in the oil layers of the Lower Triassic Baikouquan formation in Well XIA72 fault block, MA131 well block, Mabei oilfield, gas logging result shows that the total hydrocarbon content is low, and the physical and oil-bearing properties of reservoirs are poor, which affects the oil layer drilling rate and the later horizontal well deployment. According to the core, logging and seismic data, the genesis, identification and distribution of calcareous sandy conglomerate in the Baikouquan formation, Well XIA72 fault block were discussed. The results show that the calcareous cement in the calcareous sandy conglomerate in the study area was formed in the late diagenetic stage, and it has a destructive effect on the reservoir. The distribution of the calcareous sandy conglomerate is mainly controlled by sedimentary facies and early faults, with the logging responses characterized by high resistivity, high density and low interval transit time, which are reflected as “bright spots” on the seismic section. The distribution of the calcareous sandy conglomerate in the study area was predicted by means of the maximum likelihood system, root mean square amplitude and maximum amplitude, among which the last one can accurately reflect the distribution. The calcareous sandy conglomerate in the study area is found in massive distribution controlled by sedimentary microfacies and NW trending banded distribution controlled by faults. According to the prediction results, the deployment of 27 horizontal wells was optimized. Figures and Tables | References | Related Articles | Metrics

Stratigraphic Division and Correlation of Carboniferous Strata in Well Che 47 in Chepaizi Area CHEN Jiangxin, XU Qian, LI Yongjun, ZHU Ming, XU Miao, ZHENG Menglin 2022, 43 (4):  410-416.  doi: 10.7657/XJPG20220405 Abstract ( 271 )   HTML ( 11 )   PDF (11217KB) ( 89 )   Save The 3 370.0-3 456.5 m interval of Well Che 47 in the Chepaizi area is composed of grey-black gravel-bearing medium-coarse-grained lithic sandstone, dark-grey-grey-black gravel-bearing lithic sandstone interbedded with sandstone and carbonaceous siltstone. Its rock assemblage can be correlated with that of the top of the six member of Hala’alat formation on formation section and in Baibandi area. The Late Carboniferous sporopollen fossils such as Protohaploxypinus clarus, P. verrucosus, P. junggarensis, P. jimsarensis, Noeggerathiopsidozonotriletes multirugulatus were found in the carbonaceous siltstone, roughly dated to the Moscovian. The upper interval (2 551.2-3 370.0 m) of Well Che 47 mainly consists of basalt-andesite volcanic breccia, volcanic agglomerate, etc., with very little volcanic lava. The rock assemblage in the upper interval is different from the first to fourth members dominated by volcanic lava of Hala’alate formation, and also significantly distinct from the lower member of Aladeyikesai formation. In addition, this upper interval is above the lithic sandstone at the top of the sixth member of Hala’alate formation, and is well correlated with the seventh member (zircon U-Pb age of 306.9 Ma and 304.5 Ma) on the formation section. Thus, this upper interval is dated to the Late Carboniferous Kasimovian. Figures and Tables | References | Related Articles | Metrics

Sedimentary Characteristics and Connectivity of Upper Wuerhe Formation in Wellblock Ke 75, Karamay Oilfield LIU Nianzhou, LI Bo, ZHANG Yi, WU Min, WANG Quan, SU Hang 2022, 43 (4):  417-424.  doi: 10.7657/XJPG20220406 Abstract ( 289 )   HTML ( 13 )   PDF (2524KB) ( 179 )   Save The upper Wuerhe formation in Wellblock Ke 75 in Karamay oilfield, Junggar basin has strong heterogeneity and varying connectivity between adjacent wells, and the understanding of sand body distribution in the formation is greatly different from the previous one. It is necessary to study the sedimentary facies and sand body connectivity to clarify reservoir distribution. Taking the upper Wuerhe formation in the Wellblock Ke 75 as an example, the characteristics and styles of the 4th-order architectural elements for each subfacies belt of alluvial fan controlled by both debris flow and braided channel were discussed according to the principles of sedimentology, and the sedimentary characteristics and sand body connectivity of each architectural style were analyzed. The research shows that when the electrical properties and sedimentary cycle characteristics of neighboring wells in the sheet flow zone at fan root are consistent, the sand body connectivity is good, and when the cross flow sand bodies or cross flow fine-grained sediments are developed, the sand body connectivity is poor, leading to difficulties in forming effective reservoirs. The research confirmed a Class I favorable gas reservoir area in the Wellblock Ke 75 in Karamay oilfield. Figures and Tables | References | Related Articles | Metrics

RESERVOIR ENGINEERING

Semi-Analytical Model and Flow Characteristics of Asymmetrically Fractured Off-Center Vertical Wells in Tight Gas Reservoirs WANG Yufeng, JI Anzhao, ZHANG Guangsheng, CHEN Zhanjun 2022, 43 (4):  425-432.  doi: 10.7657/XJPG20220407 Abstract ( 221 )   HTML ( 5 )   PDF (696KB) ( 122 )   Save To understand the flow regime of asymmetrically fractured off-center vertical wells in tight gas reservoirs,a mathematical model for asymmetrically fractured off-center vertical wells was established according to the mass conservation equation. The bottom-hole pseudo pressure of off-center vertical well in Laplace space was obtained by using Laplace transform and numerical discretization. The time-space distribution of pressure and production were determined by using the Stehfest numerical inversion method,and the impacts of fracture angle,dimensionless fracture conductivity and eccentric distance on bottom-hole pseudo pressure and production were discussed. With the help of Saphir well test interpretation software,the numerical model of gas well was built and the numerical calculation for discretization was performed. The calculated results were compared with the semi-analytical solution to verify the mathematical model. Furthermore,according to the variation characteristics of the dimensionless bottom-hole pseudo pressure,the fluid flow in asymmetrically fractured off-center vertical wells was divided into six stages: bilinear flow stage in reservoir and fracture,linear flow stage in reservoir,elliptical flow stage in fracture,plane radial flow stage,near-fracture boundary-dominated flow stage,and circular closed boundary-dominated flow stage. Figures and Tables | References | Related Articles | Metrics

Influences of Cemented Natural Fractures on Propagation of Hydraulic Fractures CHENG Zhenghua, AI Chi, ZHANG Jun, YAN Maosen, TAO Feiyu, BAI Mingtao 2022, 43 (4):  433-439.  doi: 10.7657/XJPG20220408 Abstract ( 249 )   HTML ( 8 )   PDF (2487KB) ( 206 )   Save In order to determine the role of natural fractures in the forming of hydraulic fracture network in tight sandstone reservoirs, a numerical model was established using the coupled hydraulic-mechanical-damage (HMD) model, and a fracture network model was generated in the numerical model by the Monte-Carlo method. With these models, the influences of natural fracture orientation, natural fracture strength, horizontal principal stress difference, fracturing fluid injection rate and fracturing fluid viscosity on the propagation of hydraulic fractures were analyzed. The results show that when the angle between the natural fracture and the maximum horizontal principal stress direction ranges from 30° to 60°, the induced hydraulic fractures are the most complex. The increase in natural fracture strength is not conducive to the generation of branch and steering fractures. Under the condition of low horizontal principal stress difference, the orientation of natural fractures dominates the extension of hydraulic fractures. Under the condition of high horizontal principal stress difference, stress dominates the extension of hydraulic fractures. When the horizontal principal stress difference falls between 3.0 and 4.5 MPa, the hydraulic fractures exhibit the highest complexity and the largest extension. Increasing the injection rate of fracturing fluid can promote the formation of complex hydraulic fracture network. Appropriately increasing the viscosity of fracturing fluid can promote fracture propagation, but too high viscosity can only lead to complex fractures in limited areas around the perforations. Figures and Tables | References | Related Articles | Metrics

Production Performance Analysis and Productivity Prediction of Horizontal Wells in Mahu Tight Conglomerate Reservoirs：A Case of Ma 131 Dense-Spacing 3D Development Pad CAO Wei, XIAN Chenggang, WU Baocheng, YU Huiyong, CHEN Ang, SHEN Yinghao 2022, 43 (4):  440-449.  doi: 10.7657/XJPG20220409 Abstract ( 285 )   HTML ( 18 )   PDF (1161KB) ( 266 )   Save In order to clarify the productivity and production performance of Ma131 dense-spacing 3D development pad,the production characteristics and unstable production/productivity were predicted,a workflow for performance analysis and productivity prediction was established,and the key parameters such as equivalent formation permeability and effective fracture half-length,etc. were determined for single well productivity prediction. Oil in the target reservoir is easy to be degassed,which may be effectively alleviated by running the gas nozzle into the hole in the early stage. The use of over-sized oil nozzle in the early stage of flowback may greatly decrease the fracture volume; in this case,a pressure-managed flowback is necessary. The P50 productivity prediction results obtained from the production decline curves and the analytical model can complement each other,providing a more accurate and reasonable productivity prediction interval. The average effective fracture half-length of horizontal well in T1b3 is greater than that in T1b1 2; therefore,the well spacing can be further optimized. Figures and Tables | References | Related Articles | Metrics

EOR Mechanism of Compound Gas Injection After Multiple Cycles of Oxygen-Reduced Air Huff and Puff in Heavy Oil Reservoirs GUO Xiaozhe, ZHAO Jian, GAO Wanglai, PU Yanan, LI Chenggeer, GAO Neng 2022, 43 (4):  450-455.  doi: 10.7657/XJPG20220410 Abstract ( 234 )   HTML ( 5 )   PDF (557KB) ( 132 )   Save For heavy oil reservoirs, the enhanced oil recovery (EOR) mechanism of injecting different gases or compound of gases after multiple cycles of oxygen-reduced air huff and puff following water flooding is unclear. In this paper, experiments were conducted with one-dimensional and three-dimensional physical models, and numerical simulations were performed on well pair model and inverted five-spot well pattern model. Based on the comparative analysis on production and components of oil recovered in different cycles of huff and puff and flow process research, the oil displacement and washing mechanisms during huff and puff with three gases, i.e. oxygen-reduced air, CO2 and natural gas, in heavy oil reservoirs were discussed. The results show that the EOR mechanism of oxygen-reduced air huff and puff is dominated by water plugging, and the water front may readily break through after multiple cycles of operation and then fail quickly. The huff and puff with CO2 slug followed by oxygen-reduced air plays a synergy of water plugging and remaining oil displacement. The huff and puff with oxygen-reduced air injection followed by natural gas dissolves the heavy components of the oil in near-wellbore area, achieving multiple effects of increasing energy, reducing viscosity and dredging pores. EOR mechanisms of huff and puff with three gases and their compound have been clarified through the experiments and numerical simulations on 10 cycles of huff and puff, and have been verified by field wells. The conclusions are of guiding significance for enhancing oil recovery by gas huff and puff in similar reservoirs. Figures and Tables | References | Related Articles | Metrics

Production Mechanism of Mud and Sand in Ordovician Carbonate Reservoirs in Halahatang Oilfield, Tarim Basin BAI Xiaofei, ZHOU Bo, DONG Changyin, WANG Fangzhi, LIU Xiao, GAN Lingyun, REN Jinming 2022, 43 (4):  456-462.  doi: 10.7657/XJPG20220411 Abstract ( 203 )   HTML ( 3 )   PDF (1732KB) ( 154 )   Save In order to clarify the mechanism of wellbore instability in the Ordovician reservoirs of Halahatang oilfield, the rock, sand particle size and mineral composition of washed-out sand samples were mainly analyzed. It is found that wellbore instability in the Ordovician carbonate reservoirs in the study area occurs in two modes: (1) collapse of wellbore in the upper unplugged non-producing horizon (Tumuxiuke formation), that is, macroscopic instability, which results in collapsed rock blocks; and (2) production of sand carried by the fluids from key producing horizons, that is, microscopic instability, which causes the wellbore blockage by sand and mud generated from the cracking of fracture fillings and the exfoliated fine-grained components from micro-convex. The main controlling factors of wellbore instability were analyzed with the grey relational method, indicating that reservoir burial depth, wellbore diameter, water cut and wellbore azimuth are the main factors affecting wellbore instability. The wellbore diameter, wellbore azimuth and production system can be optimized to prevent and control the production of mud and sand. Figures and Tables | References | Related Articles | Metrics

Factors Influencing Effective Storage Capacity of Abnormally-High-Pressure Water-Containing Condensate Gas Reservoirs FAN Jiawei, WU Zangyuan, YU Song, ZHOU Daiyu, YAN Gengping, WANG Chao 2022, 43 (4):  463-467.  doi: 10.7657/XJPG20220412 Abstract ( 254 )   HTML ( 4 )   PDF (561KB) ( 121 )   Save As a key parameter, the effective storage capacity of a UGS affects the function, peaking capability, parameters and design of the UGS, so its accurate evaluation is very important. When converting an abnormally-high-pressure water-containing condensate gas reservoir into a UGS, factors such as abnormally high pressure, water intrusion and reverse condensate affect the storage capacity. Considering abnormally high pressure, the upper limit of the pressure for the UGS is designed to be 58.00 MPa, which is much lower than the original formation pressure. The difference of the gas volume coefficient results in the difference of the storage capacity of the UGS. During the injection-production process, water flows back and forth in the UGS, which dramatically affects the utilization of reservoir space. In the alternative production-injection process, when the formation pressure is lower than the dew point pressure, separated condensate oil has a certain influence on the storage capacity. In response to this problem, an improved dual model integrating material balance and numerical simulation was established. Based on the dynamic reserves of gas reservoirs, factors such as abnormal high pressure, reverse condensation, water intrusion were quantitatively analyzed, and a set of methods for evaluating the capacity of the UGS were developed. The set of methods was applied for constructing the Lunnan-59 Carboniferous UGS. The effective storage capacity of the UGS was accurately evaluated. This lays a foundation for the research on the parameters of the UGS, and ensures the successful construction of the Lunnan-59 Carboniferous UGS. Figures and Tables | References | Related Articles | Metrics

APPLICATION OF TECHNOLOGY

Experimental Evaluation on Microsphere-Natural Gas Flooding in Buried-Hill Reservoirs CHEN Shijie, SUN Lei, PAN Yi, WANG Yajuan, LIN Youjian, CHEN Fenjun 2022, 43 (4):  468-473.  doi: 10.7657/XJPG20220413 Abstract ( 207 )   HTML ( 3 )   PDF (761KB) ( 130 )   Save During the development of fractured buried-hill reservoirs which are highly heterogeneous, fingering and channeling occur frequently; therefore, blocking high permeability channels such as fractures and large pores is an effective measure to improve oil recovery of these reservoirs. Through laboratory experiments on flowing in the cores from the B1 buried-hill reservoir, the plugging effect of microspheres on both fractures and large pores in the cores was evaluated, and the effectiveness of microsphere-natural gas flooding to improve the recovery of remaining oil was discussed. The results show that the oil displacement efficiency of water flooding or natural gas flooding is inapparent. When microsphere flooding is adopted, the microspheres significantly increase the resistance coefficient and injection pressure due to their expansion and plugging after entering the core. The microsphere size directly affects the plugging effect. If the microsphere size is too small, good plugging effect cannot be achieved; if the microsphere size is too large, microsphere injection is difficult. The expansion, plugging, unplugging, deformation plugging of the injected microspheres and the dissolution of the injected natural gas are synergic to effectively inhibit the fingering and channeling of displacing fluid during the development of fractured buried-hill reservoirs. Therefore, microsphere-natural gas flooding can greatly improve the recovery degree of remaining oil. Figures and Tables | References | Related Articles | Metrics

Experimental Correction of Dual Lateral Reservoir Resistivity After High Salinity Drilling Fluid Invasion MU Liwei, WANG Gang, LUO Xingping, FAN Haitao, LIN Shijun, WANG Guohui 2022, 43 (4):  474-478.  doi: 10.7657/XJPG20220414 Abstract ( 182 )   HTML ( 6 )   PDF (570KB) ( 136 )   Save In order to eliminate the influences of high salinity drilling fluid invasion on dual lateral resistivity, it is necessary to restore the real resistivity of formation. By analyzing the factors influencing rock electric experiment, the electrode system and measuring technology were improved to make the resistivity of the rock sample from impermeable layers consistent with the double lateral resistivity. Under the conditions of high temperature and high pressure, the rock electric parameters were measured with the semi-permeable baffle plate gas flooding method, and then the drilling fluid invasion was simulated by displacing the oil in rock samples with high salinity drilling fluid. Finally, the relationship between rock sample resistivity and logging resistivity was established and a correction method for logging resistivity based on experiment was formed. The application of the method in multiple wells in the hinterland of Junggar basin shows that the gas saturation calculated with the corrected resistivity is more reasonable. The method provides an effective means for logging response analysis and reservoir evaluation. Figures and Tables | References | Related Articles | Metrics

Factors Influencing Productivity of Horizontal Wells With CO2 Inter-Fracture Flooding XIAO Hanmin, LUO Yongcheng, ZHAO Xinli, ZHANG Haiqin, LIU Xuewei 2022, 43 (4):  479-483.  doi: 10.7657/XJPG20220415 Abstract ( 218 )   HTML ( 7 )   PDF (1922KB) ( 135 )   Save When tight oil reservoirs are developed by depletion mode, oil production declines rapidly. In order to explore a more effective development technique, a CO2 inter-fracture flooding model for horizontal well was established using the CMG-GEM software to simulate how the factors such as CO2 injection volume, injection pressure, reservoir temperature, fracture spacing and fracture length affect horizontal well productivity. The results show that CO2 inter-fracture flooding in a horizontal well can greatly increase the CO2 swept area, fully exploit the remaining oil, and improve the development effect. When the injection pressure is 25 MPa, the CO2 injection volume is close to and not more than 10×104 m3. The peak production rate rises with the increase of injection pressure, fracture spacing and fracture half-length. The peak production rate at the reservoir temperature of 80°C is higher than that at other temperatures; however, the higher the reservoir temperature, the less time will be needed to reach the peak daily production rate. Figures and Tables | References | Related Articles | Metrics

Comprehensive Evaluation on Steam Chamber Location and Production Prediction of SAGD in Heavy Oil Reservoirs GUO Yunfei, LIU Huiqing, LIU Renjie, ZHENG Wei, DONG Xiaohu, WANG Wuchao 2022, 43 (4):  484-490.  doi: 10.7657/XJPG20220416 Abstract ( 262 )   HTML ( 5 )   PDF (673KB) ( 185 )   Save Production and steam chamber location are critical for steam assisted gravity drainage (SAGD) in heavy oil reservoirs. The existing prediction model only considers the lateral expansion of steam chamber and cannot predict the production of adjacent wells after steam chamber contact. According to the different characteristics of the steam chamber in the lateral expansion stage and the downward expansion stage, a parameter of thermal penetration depth was introduced, the flow potential function was modified, and a parabolic production prediction model was established. The results show that the production increases gradually in the initial lateral expansion stage of steam chamber, and then decreases due to the reduction of the inclination of the steam chamber interface; in the downward expansion stage of steam chamber, the production further decreases. The model analysis reveals that SAGD is more suitable for thick reservoir development, and the optimal well spacing needs to be determined depending on the oilfield conditions. The parabolic production prediction model takes the characteristics of the steam chamber into account in the downward expansion stage, and the accuracy of the model is verified by comparing with the previous experimental data. Figures and Tables | References | Related Articles | Metrics

Core Experiment and Stimulation Mechanism of Unstable Waterflooding in Low Permeability Reservoirs ZHOU Jinchong, ZHANG Bin, LEI Zhengdong, SHAO Xiaoyan, GUAN Yun, CAO Renyi 2022, 43 (4):  491-495.  doi: 10.7657/XJPG20220417 Abstract ( 291 )   HTML ( 11 )   PDF (1256KB) ( 205 )   Save According to the typical characteristics of low permeability reservoirs in Changqing oilfield, parallel core and double-layered core experiments were carried out to simulate the effect of unstable waterflooding in heterogeneous low permeability reservoirs. Due to the poor visibility of core experiments, numerical models for simulating interlayer and intralayer heterogeneous reservoirs were established, which may reveal the stimulation mechanism of unstable waterflooding according to the change of flow field. The results show that for interlayer heterogeneous reservoirs, compared with continuous waterflooding, unstable waterflooding can promote the advancement of the flooding front in the layers with lower permeability, and give full play to capillary force in oil displacement, so unstable waterflooding can significantly improve the oil recovery of the layers with lower permeability, and the pattern of short-term injection combined with long-term quit can enhance the recovery rate the most. For intralayer heterogeneous reservoirs, unstable waterflooding can generate pressure oscillations in the layers to enable the fluid percolation between the higher permeability layers and the lower permeability layers, so that the sweep efficiency of injected water in the lower permeability layers is increased and the recovery rate of the lower permeability layers is enhanced, thereby increasing the total oil recovery rate of the reservoir. Figures and Tables | References | Related Articles | Metrics

OIL AND GAS GEOLOGY ABROAD

Dominant Water Flow Channels in Block VI of North Buzachi Oilfield CHI Yungang, TANG Zhixia, WEI Jing, ZHOU Huize, ZHANG Wenhui 2022, 43 (4):  496-504.  doi: 10.7657/XJPG20220418 Abstract ( 263 )   HTML ( 7 )   PDF (968KB) ( 183 )   Save In order to understand the development characteristics of the dominant water flow channels in the North Buzachi oilfield, the dominant water flow channels in the target layers in Block VI of the oilfield were identified by using streamlined numerical simulation technology, and the development degree and formation pattern of the dominant water flow channels were quantitatively characterized. The results show that Class Ⅰand Ⅱ channels in the study area are the water flow channels with ineffective circulation, with water flooding sweep coefficient of only 0.120-0.175. For Class I channels, the water cut at the producer is greater than 97%, and the average sweep coefficient is 0.120, with extremely serious channeling. For Class II channels, the water cut at the producer ranges from 93% to 97%, and the average sweep coefficient is 0.175, with serious channeling. The dominant water flow channels are small in number and limited in volume, but they occupy most of the water volume, which results in inefficient water injection. The number of dominant channels is inversely proportional to the distance between injector and producer. The location of the main river channel is the main area where the dominant water flow channels are formed, especially in the direction that the connection line between the injector and the producer is parallel to the sedimentary direction of the main river channel. The longer the producing time of the producer and injector, and the higher the ratio of cumulative liquid production to water injection, the higher the probability of dominant channel occurs near the wells with high daily liquid production. Furthermore, the dominant water flow channels change with the initial production time of the producer and the adjustment of injector-producer relationship. Figures and Tables | References | Related Articles | Metrics