Lithologic Reservoirs

Based on the existing research results and shortcomings of distributive fluvial system(DFS), the key scientific issues, main research contents, research methods and workflow in DFS research were discussed. The results show that:(1) There are three critical scientific issues in DFS sedimentology research including modelling the river channel network and their evolution, constructing sedimentary model and analyzing the control factors influencing DFS formation and distribution.(2) The main directions in DFS research are to build sedimentological database, to study on modern DFS deposition mechanism and DFS classification, and to establish DFS sedimentary model, DFS reservoir modeling and reservoir prediction.(3) The key technologies necessary to strengthen the research include DFS morphological and sedimentological data collection based on remote sensing images, flume experiment and digital simulation of DFS formation mechanism, DFS river channel network reconstruction, DFS apex estimation and automatic branching point prediction and DFS reservoir modeling knowledge base construction.(4) The work processes of DFS research have three main steps in which the first step is to establish the DFS geomorphological and sedimentological data base and the related software platform, the second step is to carry out DFS classification by integrating the modern sedimentary investigation, outcrop anatomy and simulation experiment research, and the final is to summarize the facies identification marks and to build the sedimentary models of various DFS. Based on the above, the reservoir prediction models and the software platform can be established for hierarchically reservoir modeling, so as to predict the favorable reservoir distribution in depositional system.

Paleotectonic stress field and fracture characteristics of shales of Ordovician Wufeng Formation to Silurian Longmaxi Formation in southern Fuling area，Sichuan Basin

BAO Hanyong, LIU Chao, GAN Yuqing, XUE Meng, LIU Shiqiang, ZENG Lianbo, MA Shijie, LUO Liang

2024, Vol.36(1): 14–22 Abstract ( 102 ) PDF (4812 KB) ( 150 )

doi: https://doi.org/10.12108/yxyqc.20240102

Through rock mechanics experiment, acoustic emission experiment, comprehensive interpretation of seismic data, the finite element numerical simulation method was used to numerically simulate the paleotectonic stress field of marine shales of Ordovician Wufeng Formation to Silurian Longmaxi Formation in southern Fuling area. Combined with the measured results of cores, the development characteristics of structural fractures were predicted. The results show that:(1) The distribution of tectonic stress and fractures in southern Fuling area during the main formation period of fractures(the Late Yanshanian) was influenced by faults, rock mechanical properties, and tectonic stress. In areas where faults are widely developed, stress concentration can easily occur and cause large stress gradients.(2) Coulomb-Moore fracture criterion was used to predict the development of structural fractures in the study area, and the shear fracture index R was introduced to quantitatively characterize the strength of fracture development. The larger the value, the higher the degree of fracture development. Narrow and steep fault anticlines and fractures are developed near faults, mainly with high angle shear fractures, while the development of fractures is weakest in the wide and gentle synclines. The stress in the siliceous shales at the bottom of the Wufeng Formation Longmaxi Formation in the study area is concentrated, and the fractures are the most developed.(3) There are three favorable zones for the preservation of marine shale gas in the southern Fuling area:The Fenglai syncline, which is far away from the major faults and has not suffered significant damage during the main structural deformation period, is located in the low stress area with good preservation conditions, and is classified as class Ⅰ favorable zone;The Baima syncline, with small faults developed, stress values at a moderate level and moderate preservation conditions, is classified as class Ⅱ favorable zone;The Shimen-Jinping fault anti-cline, which has undergone strong transformation and is prone to large-scale shear fractures, making the preservation conditions damaged, is classified as class Ⅲ unfavorable zone.

Fluid phase and hydrocarbon reservoir types of Permian Upper Urho Formation in Shawan Sag，Junggar Basin

WANG Jinduo, ZENG Zhiping, XU Bingbing, LI Chao, LIU Dezhi, FAN Jie, LI Songtao, ZHANG Zengbao

2024, Vol.36(1): 23–31 Abstract ( 97 ) PDF (4122 KB) ( 188 )

doi: https://doi.org/10.12108/yxyqc.20240103

There are abundant oil and gas resources in the super-deep strata of Shawan Sag in the hinterland of Junggar Basin. Thermal evolution simulation of source rocks was carried out to analyze the types of hydrocarbon generation products of source rocks of Permian Upper Urho Formation in Shawan Sag. Based on the experimental data of the high-temperature and high-pressure physical properties of the formation fluid, the formation fluid phase of well Zheng10 in Shawan Sag was studied by using phase diagram discrimination method and empirical parameter method. The results show that:(1) The oil and gas of Upper Urho Formation of well Zheng 10 in Shawan Sag mainly came from the argillaceous source rocks of Lower Urho Formation, with an organic matter type of Ⅱ1, a vitrinite reflectance(Ro) of 1.05% to 1.46%, and a rock pyrolysis peak temperature(Tmax) of 433℃ to 446℃. It is in the mature to high mature evolution stage and currently in the stage of light oil generation.(2) The fluid composition of the Upper Urho Formation is conforming to the fluid composition of condensate gas reservoir, with a formation temperature of 166.0℃, which is between the critical temperature and the critical condensate temperature. The formation pressure is 155 MPa, much higher than the dew-point pressure, with a large surface and dew-point pressure difference, indicating that the fluid exhibits condensate gas phase characteristics under formation conditions, but there are certain differences between the underground oil and gas phase state and the surface produced fluid phase state. Both the phase diagram discrimination method and the empirical parameter method show that the gas reservoirs of Upper Urho Formation in well Zheng 10 are condensate gas reservoirs with a large oil-ring.(3) The Upper Urho Formation in Shawan Sag has superior hydrocarbon accumulation conditions, adjacent to the source rocks of Lower Urho Formation. Oil and gas are transported vertically near the source, migrating and accumulating towards local uplift areas. The thick Triassic and regional cap rocks of the upper part of Upper Urho Formation play an important sealing role, ultimately forming lithologic-structural condensate gas reservoirs in local uplift areas.

Tectonic-depositional environment and prototype basin evolution of Middle-Late Permian in Ordos Basin and adjacent areas

ZHAI Yonghe, HE Dengfa, KAI Baize

2024, Vol.36(1): 32–44 Abstract ( 74 ) PDF (10465 KB) ( 214 )

doi: https://doi.org/10.12108/yxyqc.20240104

According to drilling, logging, field outcrops and geochemical data, combined with peripheral tectonic environment, tectonic subsidence characteristics and sedimentary facies distribution characteristics, the tectonic depositional environment in different periods of Middle-Late Permian in Ordos Basin was restored, and the nature and evolution of the basin were discussed. The results show that:(1) The northern and southern margins of Ordos Basin experienced subduction of ocean basins in the Middle to Late Permian, which was characterized by strong compressive tectonic environment. During the sedimentary period of Upper Permian Shiqianfeng Formation, the northern margin of Ordos Basin entered the stage of continental collision when the Paleo-Asian Ocean closed, and the tectonic subsidence in the basin was slow.(2) The Ordos Basin was a large intra-craton depression basin in Middle-Late Permian, and the base level of Middle Permian Shihezi Formation showed a downward trend. The main part of the basin followed the paleogeographic pattern of Shanxi Formation, which was high in the north and south and low in the middle, and the topography of the southern North China was relatively lower. The surrounding uplift areas were rapidly uplifted and gradually expanded, providing provenance for the depression basin. Alluvial fans, alluvial plains, deltas and shallow lacustrine facies developed in the basin. To the south, the remaining tidal flat-lagoon was developed, showing a north-south distribution. In the Late Permian, with the base level tended to be stable, the lacustrine scope expanded and the tidal flat-lagoon environment narrowed southward.(3) The sedimentary environment in the study area plays a controlling role in hydrocarbon accumulation. The terrestrial delta depositional system developed in Middle Permian is conducive to favorable reservoirs and cap rocks, and form favorable reservoir-reservoir-cap assemblages with lower coal measures in Middle Permian. Due to the paleoclimate of oxidation and drought in Upper Permian, shallow water bodies and thin mudstone, the hydrocarbon generation potential is limited and it cannot form large-scale gas reservoir.

Pore structure characteristics and gas-bearing properties of shale gas reservoirs of Lower Carboniferous Dawuba Formation in southern Guizhou

YANG Bowei, SHI Wanzhong, ZHANG Xiaoming, XU Xiaofeng, LIU Yuzuo, BAI Luheng, YANG Yang, CHEN Xianglin

2024, Vol.36(1): 45–58 Abstract ( 69 ) PDF (10659 KB) ( 144 )

doi: https://doi.org/10.12108/yxyqc.20240105

The pore structure characteristics and gas-bearing properties of shales of Lower Carboniferous Dawuba Formation in southern Guizhou were studied by using field emission scanning electron microscopy, whole-rock X-ray diffraction analysis, and isothermal adsorption of N2 and CO2. The results show that:(1) Calcareous shale lithofacies and calcareous/clayey mixed shale lithofacies are developed in Lower Carboniferous Dawuba Formation in southern Guizhou, with a small amount of siliceous clay shale lithofacies developed. The shale has low organic matter abundance and high maturity.(2) The pore types of shales of Dawuba Formation in the study area include inorganic pores, organic pores and microfractures, among which inorganic pores are the dominant type. The pore size distribution of shale shows a multi-peak pattern, dominated by micropores less than 1 nm and low-value mesopores of 2.0-2.4 nm and 6.0-8.0 nm. The pore volume of the shale is mainly provided by mesopores and macropores, which control the occurrence of free gas. The specific surface area of the shale is mainly provided by micropores and mesopores, which control the occurrence of adsorbed gas.(3) The gas-bearing properties of Dawuba Formation shales in the study area are mainly controlled by pore structure and preservation conditions, and organic matters and mineral components are the main factors affecting pore structure. The organic matter content and clay mineral content have a positive effect on the development of shale pores, and the brittle mineral content inhibits the development of shale pores. The complex tectonic deformation in the study area has led to poor shale gas preservation conditions, and the preservation index can be used to qualitatively-quantitatively evaluate the preservation conditions of shale gas of Dawuba Formation and make effective classification.

Reservoir characteristics and hydrocarbon accumulation rules of Triassic Baikouquan Formation in Mahu Sag，Junggar Basin

YIN Lu, XU Duonian, YUE Xingfu, QI Wen, ZHANG Jijuan

2024, Vol.36(1): 59–68 Abstract ( 83 ) PDF (7809 KB) ( 167 )

doi: https://doi.org/10.12108/yxyqc.20240106

Through core analysis and testing, seismic thickness prediction, inclusion accumulation period analysis and source-reservoir configuration study, the reservoir characteristics and hydrocarbon accumulation rules of Triassic Baikouquan Formation in Mahu Sag of Junggar Basin were studied. The results show that:(1) The Triassic Baikouquan Formation in the slope area of Mahu Sag mainly develops fan delta deposits, with generally coarse lithologies. Relatively high-quality reservoirs are mainly distributed in underwater distributary channel microfacies and a small number of mouth bar microfacies of fan delta front, dominated by feldspathic lithic sandstone conglomerate, followed by lithic sandstone conglomerate. The rocks are generally relatively dense. The core porosity ranges from 3.17% to 23.40%, with an average of 9.04%, and the permeability ranges from 0.01 mD to 934.00 mD, with an average of 0.73 mD. It belongs to low porosity and ultra-low permeability reservoirs. The main reservoir spaces are secondary dissolved pores, with intergranular fractures and other microfractures developed.(2) The oil and gas in the study area mainly come from the shale of alkali lake in Lower Permian Fengcheng Formation, with the maximum thickest greater than 400 m. It is a residual sea lagoon facies deposit with high water sali-nity, and the lithologies are mainly composed of dolomitic mudstone and mudstone. The organic matter is mainly of type Ⅰ and Ⅱ1. The total organic carbon(TOC) content is greater than 1.0%, the hydrocarbon generation potential (S1+S2) is generally greater than 6.0 mg/g, the average chloroform asphalt "A" is 0.2%, and the average HI is 322 mg/g. The organic matters are in the mature stage, and are medium-good source rocks.(3) There are three stages of hydrocarbon accumulation characteristics in the study area. Before the Late Triassic, it was the first stage of oil and gas filling, which failed to accumulate and form reservoirs. The Early Jurassic was the second stage of oil and gas filling, corresponding to yellow fluorescent hydrocarbon inclusions. The Early-Middle Cretaceous was the third stage of oil and gas filling, corresponding to blue white fluorescent hydrocarbon inclusions. The latter two stages of oil and gas filling played a major role in hydrocarbon accumulation of the Baikouquan Formation. (4) The tightness of the source-reservoir configuration in the study area is the core factor that leads to the differential accumulation of oil and gas in the west slope and east slope of Mahu Sag.

Facies-controlled karst characterization and effective reservoir prediction of Permian Maokou Formation in Yuanba area，Sichuan Basin

LI Bisong, SU Jianlong, PU Yong, MIAO Zhiwei, ZHANG Wenjun, XIAO Wei, ZHANG Lei, JIANG Yu

2024, Vol.36(1): 69–77 Abstract ( 62 ) PDF (7052 KB) ( 142 )

doi: https://doi.org/10.12108/yxyqc.20240107

Through technologies such as karst paleogeomorphology restoration, dip angle constraint enhanced coherence, facies-controlled karst seismic inversion, and nonlinear gamma simulation, the distribution patterns of facies-controlled karst anomalies and effective reservoirs of Permian Maokou Formation in Yuanba area of Sichuan Basin were studied. The results show that:(1) The Permian Maokou Formation in Yuanba area can be vertically divided into three karst zones:surface weathered crust, vertical seepage zone, and horizontal subsurface flow zone. The facies-controlled karst reservoirs of the third member of Maokou Formation are jointly controlled by shallow shoal facies and karstification, and the reservoirs can be divided into pore-cavity type and semi-filled karst cave type.(2) The karst residual hills have relatively high landform, serving as a water supply area for karstification, and are favorable for the development of facies-controlled karst. The karst plains have relatively low landform and are catchment areas for karstification.(3) The enhanced coherence technique with dip angle constraint can qualitatively describe the favorable zones of facies-controlled karst development within the residual hills. This type of reservoir in the study area is mainly distributed in high areas of ancient landforms and is distributed in a northwest direction.(4) The prediction method of facies-controlled karst reservoirs can relatively accurately predict the distribution range of effective karst reservoirs. The karst reservoirs in the ridge and peak cluster zones in the study area are the most developed, with a maximum thickness of 28 m.

Accumulation characteristics and main controlling factors of tight sandstone of Jurassic Shaximiao Formation in southwestern Sichuan Basin

WANG Xiaojuan, CHEN Shuangling, XIE Jirong, MA Hualing, ZHU Deyu, PANG Xiaoting, YANG Tian, LYU Xueying

2024, Vol.36(1): 78–87 Abstract ( 80 ) PDF (6526 KB) ( 137 )

doi: https://doi.org/10.12108/yxyqc.20240108

The data of geological structures, organic geochemistry, reservoir properties and lithologies were used to analyze the accumulation conditions and main controlling factors of tight sandstone gas of Jurassic Shaximiao Formation in southwestern Sichuan Basin from four aspects such as source rocks, reservoir properties, effective cap rocks and migration pathways, and the favorable areas for tight gas reservoirs were predicted. The results show that:(1) Jurassic Shaximiao Formation in southwestern Sichuan Basin has good accumulation conditions for tight gas reservoirs. The organic matters in the coal measure source rocks of the fifth member of Triassic Xujiahe Formation are mainly of type Ⅲ kerogen, with an average TOC value of 3.31% and Ro of 0.70%-1.75%, which provides a good material basis for the accumulation of coal-bed methane in Shaximiao Formation. The overlying Suining Formation developed thick mudstone, with a mudstone-formation ratio greater than 0.8 and high breakdown pressure, providing a good cap rock. The widely developed gas source faults in the area provide good migration pathways for oil and gas.(2) The size of the tight sandstone gas reservoirs in the study area is controlled by the distance between the source and reservoir and reservoir properties. The geological reserves of the gas reservoir are positively correlated with reservoir properties and have a parabolic relationship with the distance between the source and reservoir. The enrichment of tight gas is controlled by the source-reservoir-cap assemblage. When the source and reservoir are separated and the regional cap is covered, the tight gas is enriched under the regional cap below the reservoir. When the source and reservoir are separated and the regional cap is cut, the dominant reservoirs are multilayered and enriched. The hydrocarbon generation potential of source rocks and migration pathways control the natural gas charging mode. The overall charging degree in the area is high, and the accumulation conditions for lateral migration and expulsion of source rocks are better than those for vertical migration and expulsion.(3) Geological reserves are linearly and positively correlated with accumulation index, with a correlation coefficient greater than 0.8. Areas with accumulation index greater than 0.4, mudstone-formation ratio greater than 0.5 and good fault sealing, are favorable for gas reservoir distribution. Tight gas reservoirs of the first member of Shaximiao Formation are mainly distributed in Minshan-Qionglai-Xinjin areas, Tianfu gasbearing areas, while the tight gas reservoirs of the second member of Shaximiao Formation are mainly distributed around Pujiang, Meishan, and Chengdu.

Source rock characteristics of Permian Pingdiquan Formation in Dongdaohaizi sag，Junggar Basin

LI Erting, MI Julei, ZHANG Yu, PAN Yueyang, DILIDAER Rouzi, WANG Haijing, GAO Xiuwei

2024, Vol.36(1): 88–97 Abstract ( 50 ) PDF (4652 KB) ( 153 )

doi: https://doi.org/10.12108/yxyqc.20240109

Dongdaohaizi sag is one of the important exploration fields for Permian in Junggar Basin, and the Permian Pingdiquan Formation is the key formation for the development of source rocks in this area. Based on the analysis of source rock distribution and geochemical characteristics of organic matters, the hydrocarbon generation potential and types of the source rocks of Pingdiquan Formation in Dongdaohaizi sag were determined. The results show that:(1) The Pr/nC17 and Ph/nC18 of Pingdiquan Formation source rocks in Dongdaohaizi sag are 0.35-1.18 and 0.23-0.81, respectively, indicating that the source rocks are mainly sourced from mixed facies, with contributions from both terrestrial and aquatic organisms.(2) Vertically, Ping-1 member and Ping-2 member have the best source rock types. The proportion of good-quality source rocks of Ping-1 member and Ping-2 member is 81.1% and 62.5%, respectively, and the average TOC is 1.88% and 1.55%, respectively. The proportion of good-quality source rocks in Ping-3 member is only 30.2%. The source rocks of Ping-1 member and Ping-2 member are mainly type Ⅱ, accounting for 66.7% and 48.4% respectively, which can generate both oil and gas. The source rocks of Ping-3 member are of poor quality, dominated by type Ⅲ kerogen, and have certain gas potential. On the plane, from marginal area to sag area, the source rocks gradually become better.(3) The source rocks in the marginal area have reached mature evolution stage, and the source rocks in the sag have large burial depth, reaching high and over-mature evolution stage. Source rocks of Pingdiquan Formation reach hydrocarbon generation threshold at about 2 500 m, and massive hydrocarbon expulsion threshold at 4 350 m. When the depth reaches 5 050 m, it is in the stage of massive pyrolysis and gas generation.(4) The distribution of oil and gas in the study area is obviously controlled by the distribution and maturity of source rocks. Therefore, mature oil is mainly found in the shallow Jurassic Badaowan Formation in the far-source denudation area, and light oil is found in Permian in sag slope area. However, the exploration in deep sag should take self-generating and self preserving gas reservoirs of Pingdiquan Formation as target.

Sedimentary facies distribution characteristics and sedimentary model of Triassic Baikouquan Formation in Shawan Sag，Junggar Basin

WANG Tianhai, XU Duonian, WU Tao, GUAN Xin, XIE Zaibo, TAO Huifei

2024, Vol.36(1): 98–110 Abstract ( 60 ) PDF (9079 KB) ( 131 )

doi: https://doi.org/10.12108/yxyqc.20240110

The Triassic Baikouquan Formation in Shawan Sag of Junggar Basin mainly develops fan delta deposits. Accurately identifying the distribution characteristics of each sedimentary facies of the fan delta is of great significance for the exploration and development of multi-type oil and gas reservoirs. Combined with high-precision three-dimensional development seismic and a large number of drilling and logging data, the distribution characteristics of sedimentary facies of Baikouquan Formation in Shawan Sag were studied by means of sedimentary facies research, seismic attribute analysis and paleotopography restoration. The results show that:(1) Baikouquan Formation in Shawan Sag can be divided into three fourth-order sequences and several fifth-order sequences. The three fourth-order sequences correspond to three members of Baikouquan Formation, and the fifth-order sequences are controlled by short-term sedimentary cycles, corresponding to different sedimentary microfacies.(2) The root mean square amplitude attribute is more sensitive to the lithology change of the target layer. The high energy zones are expressed as fan delta plain subfacies, the middle energy zones are expressed as fan delta front subfacies, and the low energy zones are expressed as the shore shallow lake subfacies.(3) During the sedimentary period of the first and second members of Baikouquan Formation, the lake basin area of the study area is small, and the fan delta plain and front subfacies are mainly developed. During the sedimentary period of the third member of Baikouquan Formation, the lake basin area is expanded, and the fan delta front and shore-shallow lake subfacies are mainly developed, which is a typical transgressive retrograding fan delta. The fan delta front subfacies have good physical properties, and are covered by mudstone of shore-shallow lake subfacies, forming a good reservoircap assemblage.(4) The Baikouquan Formation in the study area has a large scale of fan bodies and close source rocks, with lithologies mainly of sandy conglomerate, which is a gentle slope shallow water fan delta sedimentary model. The front subfacies of fan delta are potential favorable reservoir accumulation areas, which are key exploration areas for the discovery of oil and gas resources.

Restoration and characteristics of karst paleogeomorphology of Middle Permian Maokou Formation in southern Sichuan Basin

ZHANG Tan, JIA Mengyao, SUN Yaxiong, DING Wenlong, SHI Siyu, FAN Xinyu, YAO Wei

2024, Vol.36(1): 111–120 Abstract ( 58 ) PDF (7749 KB) ( 107 )

doi: https://doi.org/10.12108/yxyqc.20240111

Karst paleogeomorphology is one of the main controlling factors of sedimentary microfacies type, distribution range and reservoir development in petroliferous basins. It is very important to restore karst palaeogeomorphology to guide oil and gas exploration. Based on a large number of drilling, logging and seismic data, the denudation thickness of the unconformity interface at the top of Middle Permian Maokou Formation in southern Sichuan Basin was calculated by using sedimentation rate method and stratum thickness comparison method, and the karst paleogeomorphology units were divided according to the regional differences of the denudation thickness and paleogeomorphic indicators. The results show that:(1) The top of Middle Permian Maokou Formation in southern Sichuan Basin mainly developed parallel unconformities, and only formed angular unconformity in local areas. Under the background of stable sedimentation and weak tectonic movement in Upper Yangtze platform during Early and Middle Permian, sedimentation rate method and stratum thickness comparison method are relatively more suitable for the restoration of karst palaeogeomorphology in the study area.(2) The denudation thickness of the top of Middle Permian Maokou Formation in the study area changes from 0 to 120 m. The strongest denudation areas are near the wells LG1 and W4 in the north, which represent the highest position of the karst ancient landform. The denudation intensity gradually weakens towards the southeast, and the terrain gradually decreases. The weakest denudation areas are located in the northeast of well LS1, which represents the lowest position of the karst ancient landform. The overall landscape pattern is "high in the north, low in the south and lowest in the northeast".(3) The paleogeomorphology of Maokou Formation in the study area controls the intensity of karst development, which can be divided into three secondary karst paleogeomorphic units, namely, karst highlands, karst slopes and karst basins, and seven tertiary paleogeomorphic units, including karst peak basins, karst hill depressions, hill cluster valleys, hill cluster depressions, hill cluster gullies, peak forest plains and residual hill plains. Among them, the karst slopes are easy to form good reservoir spaces, laying a good foundation for the formation of oil and gas traps, and are the next favorable exploration direction.

Lithofacies paleogeography evolution of Late Ordovician in Sichuan Basin and its surrounding areas

SUN Hanxiao, XING Fengcun, XIE Wuren, QIAN Hongshan

2024, Vol.36(1): 121–135 Abstract ( 55 ) PDF (18117 KB) ( 102 )

doi: https://doi.org/10.12108/yxyqc.20240112

Based on outcrops, cores, drilling and logging data, the evolution process of Lithofacies paleogeography of Late Ordovician in Sichuan Basin and its surrounding areas was described and compared, and the main controlling factors were discussed. The results show that:(1) The early Caledonian tension-extension led to the deepening of the depression around the study area, and then the collision and extrusion of the Yangtze plate and Cathaysia block formed the paleogeographic pattern of the upper Late Ordovician Yangtze region as the center, surrounded by uplifts on the northwest, west and south sides.(2) The Late Ordovician in Sichuan Basin and its surrounding areas can be divided into(mixed) shore, carbonate gentle slope and(mixed) shelf sedimentary facies. The Baota Formation-Linxiang Formation mainly developed carbonate gentle slope facies. At the transgressive peak of Wufeng Formation, the carbonate gentle slope was submerged and developed(mixed) shelf deep water black shale. The regressions of Guanyinqiao Formation led to the transition from deep shelf to shallow shelf subfacies in most areas. There are(mixed) shore facies developed in the periphery of paleo-uplift in all periods, and some areas affected by provenance have mixed sedimentary characteristics.(3) The lithofacies paleogeographic pattern of the Late Ordovician in the study area is controlled by multiple factors such as tectonic movement, sea level change and paleoclimate, which is reflected in the plane distribution and vertical evolution of sedimentary facies.

Paleogeomorphology and favorable reservior distribution of the first member of Permian Lucaogou Formation in Jimsar Sag

DENG Yuan, CHEN Xuan, QIN Jianhua, LI Yingyan, HE Jixiang, TAO Xin, YIN Taiju, GAO Yang

2024, Vol.36(1): 136–144 Abstract ( 83 ) PDF (7363 KB) ( 88 )

doi: https://doi.org/10.12108/yxyqc.20240113

Based on core, logging and seismic data, the paleogeomorphology of the first member of Permian Lucaogou Formation in Jimsar Sag was restored, and the distribution of favorable reservoirs was predicted. The results show that:(1) The reservoirs of the first member of Lucaogou Formation in Jimsar Sag are rich in the sedimentary structures of massive bedding, climbing ripple bedding and plant clasts, and inversely-graded lower part and normallygraded upper part with internal scour surface, which can be interpreted as the origin of lacustrine hyperpycnite. The main microfacies are channel, levee, lobe and margin, among which channel and lobe are favorable reservoirs.(2) During the depositional period of the first member of Lucaogou Formation, the paleogeomorphology of Jimsar Sag showed a pattern of "low in the south and high in the north, and low in the middle and high in the east and west". Three kinds of micro-paleogeomorphology units developed in low position:paleo-groove, paleo-low uplift and paleo-platform. In the paleo-groove, the reserviors present a stacking pattern of aggradation and thick layer filling. The reserviors in palaeo-platform are progradational and lateral stacking pattern with thin layer sheet distribution. The paleo-low uplifts separate the hyperpycnite lobes. The paleo-slope area is lack of hyperpycnite. (3) There are three hyperpycnal channles in southern Jimsar Sag. The channels prograde northward, and the main channles are dispersed into multiple branches, forming multiple overlapping lobes at the end of channles.

Sequence stratigraphy and evolution of Triassic Chang 7 to Chang 3 mebers in Qingcheng area，southwestern Ordos Basin

LONG Shengfang, HOU Yunchao, YANG Chao, GUO Yixuan, ZHANG Jie, ZENG Yali, GAO Nan, LI Shanghong

2024, Vol.36(1): 145–156 Abstract ( 93 ) PDF (12351 KB) ( 182 )

doi: https://doi.org/10.12108/yxyqc.20240114

The methods such as fine calibration of well-seismic fine calibration, constraint of tuff marker layer and forward modeling of velocity were used to establish isochronous stratigraphic framework of Chang 7 to Chang 3 members of Triassic Yanchang Formation in Qingcheng area, southern Ordos Basin, and the stratigraphic evolution characteristics were analyzed. The results show that:(1) The lake flooding mudstone of Triassic Chang 7-Chang 3 members in Qingcheng area is characterized by high gamma ray, high acoustic wave and medium to high resistivity. The individual lake flooding mudstone layer is horizontally inclined to the center of the lake basin, which can extend from the traditional members of Chang 3 to Chang 7, with isochronal correlation significance. The fine-grained sediments developed in Chang 4+5 member are the superimposed response result of lake flooding in different periods. (2) The Chang 7 to Chang 3 members in study area is bounded by lake flooding mudstone, and can be divided into seven isochronous stratigraphic units(Pss1-Pss7) from bottom to top, which are superim-posed on each other horizontally and flow towards the center of the lake basin, and are vertically manifested as the "ternary" structure of top set, oblique set and bottom set.(3) In the study area, Chang 7-Chang 3 members are generally characterized by progradation filling under the background of shock lake regression, and its evolution can be divided into three stages. The first stage(Pss1-Pss2) is in the early filling stage, with relatively gentle slope, and the strata are generally in the form of wedge aggradation-weak progradation superposition. In the middle stage(Pss3-Pss5), with the progradation slope advancing to the semi-deep lake-deep lake area, the slope became larger, and the strata were mainly characterized by "S" type progradation structure, with delta front deposits widely developed in the top set, and gravity flow sand bodies of deep lake facies developed in the bottom set. In the late stage(Pss6-Pss7), the lake basin shrank, the water body became shallower, the slope height and angle became smaller, the top set developed delta plain facies deposits, the middle and upper part of the oblique set was mainly delta front deposits, and the middle and lower part of the oblique set and the front part of the bottom set were mainly delta-semi-deep lake facies muddy deposits.

PETROLEUM ENGINEERING AND OIL & GAS FIELD DEVELOPMENT

Calculation method of investigation radius of horizontal wells

ZHOU Hao, LIANG Lixia

2024, Vol.36(1): 157–168 Abstract ( 61 ) PDF (2625 KB) ( 245 )

doi: https://doi.org/10.12108/yxyqc.20240115

The principle of mass conservation was used to convert a horizontal well into a virtual vertical well, each parameter and pressure were connected through the state equation, and then the calculation method of investigation radius of horizontal wells was studied. The results show that:(1) The newly derived formula for the investigation radius is a nonlinear implicit function with respect to time.(2) The investigation radii of oil wells increase with time, and the reservoir characteristic parameters have obvious influence on the typical curve of investigation radii and time.(3) The typical curve of investigation radii of horizontal wells in multizone composite reservoir obviously shows the multizone characteristics of composite reservoir.(4) There are N-1 inflection points on the typical curve of composite reservoir in N zone, which represents the response of pressure wave to the interface of two adjacent zones. The increase of inner zone radius will make the corresponding inflection points move to the upper right corner.

Mechanism of DES+CTAB composite oil displacement agent system to improve oil recovery of low-permeability tight sandstone reservoirs

BAI Jiajia, SI Shuanghu, TAO Lei, WANG Guoqing, WANG Longlong, SHI Wenyang, ZHANG Na, ZHU Qingjie

2024, Vol.36(1): 169–177 Abstract ( 87 ) PDF (4548 KB) ( 95 )

doi: https://doi.org/10.12108/yxyqc.20240116

Aiming at the problems of difficult water injection and low recovery in low-permeability tight reservoirs, an oil displacement agent composed of urea-based deep eutectic solvent(DES) and cetyltrimethylammonium bromide(CTAB) was developed to study the mechanism of reducing pressure and increasing injection and improving recovery in low-permeability tight sandstone reservoirs. The results show that:(1) The oil displacement agent system can reduce the oil-water interfacial tension to below 10-3 mN/m, which can greatly improve the oil washing efficiency.(2) The developed oil displacement agent has good clay mineral hydration inhibition, effectively avoiding the fluid sensitivity damage caused by the hydration expansion of clay minerals in low permeability tight sandstone.(3) The oil displacement agent system can modify the interface of sandstone surface. The oil phase contact angle of the samples after soaked by the oil displacement agent system increases from 25.8° to 61.4°, the hydrophilicity increases and the lipophilicity decreases, which contributes to the shedding of the oil film adsorbed on the rock surface.(4) The average reduction rate of injection pressure of advanced injection oil displacement agent is 79.64%, and the average recovery rate is 50.96%, which is much higher than the recovery rate of conventional water flooding(primary water injection→oil displacement agent injection→secondary water injection).

Pre-CO₂ energy storage fracturing technology in horizontal wells for medium-deep heavy oil

YANG Zhaochen, LU Yingbo, YANG Guo, HUANG Chun, YI Dalin, JIA Song, WU Yongbin, WANG Guiqing

2024, Vol.36(1): 178–184 Abstract ( 58 ) PDF (2977 KB) ( 168 )

doi: https://doi.org/10.12108/yxyqc.20240117

The development mechanism, key operating parameters and development effects of CO2 energy storage pre-fracturing technology for horizontal wells were studied by using the parameters of medium-deep heavy oil reservoirs in Wuxia area, northwestern margin of Junggar Basin. The results show that:(1) With the extension of development stages such as fracturing, soaking and production, the oil wells after pre-CO2 energy storage fracturing show the characteristics of energy increase, diffusion and viscosity reduction, expansion and energy supplement, and secondary foam oil displacement. The bottom hole flowing pressure increased by 2-4 MPa, the CO2 diffused to one third of the reservoir, the crude oil viscosity decreased to less than 500 mPa·s, and the foam oil flow was obvious.(2) The optimal fracturing interval in the study area is 60 m, the half length of the fracture is 90 m, the fracture conductivity is 10 t/m, the optimal CO2 injection intensity is 1.5 m3/m, the injection rate is 1.8 m3/min, the soaking time of oil wells is 30 d, and the oil reservoir recovery factor increases by 2%-3%.(3) Compared with conventional fracturing, the pre-CO2 energy storage fracturing can increase the production by 5.2 t/d, and the oil exchange rate of CO2 is predicted to be 2.45. The development effect was significantly improved.