Table of Content

28 December 2020, Volume 41 Issue 6

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Petroleum Geology

Geochemical comparison of mudstone and shale—A case study of the 7^th member of Yanchang Formation in Ansai area, Ordos Basin

Bojiang Fan, Qiliang Mei, Xiaojun Wang, Yue Meng, Qijiang Huang

2020, 41(6):  1119-1128.  doi:10.11743/ogg20200601

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High-quality shale and mudstone source rocks are developed in the 7^th member of Yanchang Formation (Chang 7 member) in Ansai area within the Ordos Basin.A study of geochemical differences of the two rocks was considered necessary for evaluating their quality and identifying their contributions to oil and gas reservoirs.A core description of the Chang 7 member was then carried out based on 25 key exploration wells and a geochemical comparison of the rocks was also performed based on 81 mudstone and shale samples gathered from the member in the wells.The results show that both shale and mudstone samples are good source rocks with their thermal maturation and organic matter abundance values within favorable ranges, except that the shale samples are dominated by Types Ⅰ and Ⅱ₁ organic matters whereas the mudstone samples are dominated by Types Ⅱ₁ and Ⅱ₂ organic matters.Compared with mudstone in terms of geochemical features, shale has significantly higher abundance of organic matter with more shale samples having TOC values greater than 4% and is more oil-prone as it contains higher content of sapropel.Shale also has higher contents of free and pyrolysis hydrocarbons and greater hydrocarbon-generating potential than mudstone.However, it should be noted that the occurrence of more pores and micro-fractures in shale may have a greater impact on the content measurements of free hydrocarbon.Compared with shale, in which pores and micro-fractures are easily developed and serve as pathways for hydrocarbon expulsion and migration, mudstone demonstrates stronger retention capacity for hydrocarbons.In addition, there is no significant difference between shale and mudstone in terms of biomarker parameters.

Further understanding of differential accumulations of oil and water in tight sandstones with limited charging power:A case study of Chang 8 member in Huachi area, Ordos Basin, China

Zhenglu Xiao, Shijia Chen, Guanglin Liu, Pan Wang, Longxiang Tang, Zhanghao Liu

2020, 41(6):  1129-1138.  doi:10.11743/ogg20200602

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Batches of tight oil reservoirs including Jiyuan and Xifeng reservoirs were found in the 8th member of Yanchang Formation (Chang 8 member) in southwest Ordos Basin.Further exploration in the place reveals some areas with differential accumulations of oil and water such as Huachi and Chenghao areas.Nevertheless, the main controlling factors and distribution patterns of these accumulations are unknown.Based on a detailed discussion on source rock quality, source-reservoir contact relationship, sand body scale, physical properties and heterogeneity of reservoir in eastern and western Huachi area, this study explores the controlling factors and accumulation patterns of oil reservoirs in the differential areas.The results show that the pressure difference between source and reservoir is the main driving force of tight oil accumulations, but provides only limited charging power with backward migration.The factors controlling the differential accumulation of oil and water in eastern and western Huachi area are the argillaceous barriers grown between source and reservoir, sand body size and reservoir heterogeneity, of which, the argillaceous barriers control the downward migration of crude oil, the size of sand body serves as the lateral sealing for crude oil, and the reservoir heterogeneity determines the differential accumulation of crude oil in a single sand body.Given the limited charging power, reservoirs that are large in scale, good in physical properties and strong in homogeneity, are not ideal harbors for oil to accumulate.On the contrary, reservoirs that are small in scale, poor in physical properties and strong in heterogeneity, are more readily to provide lithological or physical barriers to stop the escape of oil.This understanding, quite different from the previous viewpoint that "high-quality sands indicate good oil traps", may serve to shed light on the further exploration in the differential areas of the Ordos Basin.

Evolutionary characteristics of Linhe Depression and its surrounding areas in Hetao Basin from the Mesozoic to Cenozoic

Ruifeng Zhang, Fusheng Yu, Xiheng Liu, Jing Liu, Shuguang Chen, Chenlin Wu, Yiqun Wang, Shengliang Wang

2020, 41(6):  1139-1150.  doi:10.11743/ogg20200603

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A major breakthrough, marked by two high-yield wells (Jihua 2X and Song 5), has been made recently in the Linhe Depression of the Hetao Basin after more than 40 years of exploration, thus revealing the great hydrocarbon potential of its Mesozoic-to-Cenozoic strata.A study on the tectonic evolution of the basin from the Mesozoic to Cenozoic may be of great contribution to the analysis of the deposition process and conditions for forming oil/gas traps.As a result, an integrated analysis of field outcrops, cores, geophysical data, and structural evolution of the basin was carried out and shows that a variety of structural deformation patterns are developed in the Linhe Depression and its surrounding areas from the Mesozoic to Cenozoic, including compression, extension, strike-slip, and inversion structures.The study area thereby experienced multiple-stage evolution from compressional depression (during the deposition of Lisangou Formation in the Early Cretaceous), depression-to-faulting conversion (during the deposition of Guyang Formation in the Early Cretaceous), uplifting and denudation (during the Late Cretaceous to Palaeocene), to weakly rifted depression (during the Eocene to Oligocene), strongly faulted depression (during the Miocene to Pliocene), and strike-slip transformation (during the Pleistocene to Holocene).The basin belongs to the multi-cycle superimposed type.And a genetic basin model was established to incorporate an early differential compression and a superimposition with late differential extension.

Alteration of reservoir-caprock systems by using CO₂-rich fluid in the Huangqiao area, North Jiangsu Basin

Bing Zhou, Zhijun Jin, Quanyou Liu, Zengmin Lun, Qingqiang Meng, Dongya Zhu

2020, 41(6):  1151-1161.  doi:10.11743/ogg20200604

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The mechanisms of CO₂-rich fluid in the alteration of reservoir-caprock systems are worthy of study for understanding the links between hydrocarbon accumulation and CO₂ activities, exploring the possibility of geological storage of CO₂ and improving the effectiveness of enhanced oil recovery (EOR) with CO₂ flooding.This study is focused on a comparison of reservoir-caprock systems with and without CO₂ fluid activities in the Longtan and Dalong Formations of the Permian in the Huangqiao and Jurong areas, North Jiangsu Basin, Lower Yangtze region.The results based on thin sections observation, mineral composition and carbon isotope analyses of the areas show that the authigenic minerals in the reservoirs of the Huangqiao area are dominated by secondary overgrowth of quartz and kaolinite, followed by a small amount of dawsonite, whereas those in the Jurong area contain no dawsonite at all and have only limited amount of secondary quartz.The reservoir porosity of the Huangqiao area is markedly higher than that of the Jurong area.Thin section observation reveals a large number of dissolved pores in feldspar occasionally with dawsonite in samples from the Huangqiao area—a piece of direct evidence of interaction between CO₂ and feldspar.Both caprocks in the two areas are black blocky mudstones.There are micro-cracks refilled with calcite veins in the caprocks of the Huangqiao area.And carbon isotope data show that the calcite veins are the result of CO₂-rich fluid activities.While few cracks and mineral veins are discovered in the mudstone caprocks from the Jurong area.These results indicate that the charging of CO₂-rich fluid in the reservoirs caused large-scale dissolution of feldspar, which increased pore space and precipitation of typical authigenic mineral assemblages of dawsonite, secondary quartz and kaolinite.The continuous activities of the CO₂-rich fluid led to precipitation of calcite and subsequent filling-up of cracks and pores in the caprocks, thus providing a better sealing effect.

Characteristics and controlling factors of pore structures of various lithofacies in shales of Longmaxi Formation, eastern Sichuan Basin

Jianfeng Huo, Jian Gao, Xiaowen Guo, Jizheng Yi, Zhiguo Shu, Hanyong Bao, Rui Yang, Tao Luo, Sheng He

2020, 41(6):  1162-1175.  doi:10.11743/ogg20200605

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The eastern Sichuan Basin is one of the major shale gas producing areas in China.However, with gas being mostly found in the clay-rich siliceous shale, the silica-rich argillaceous and mixed argillaceous/siliceous shales in the Wufeng-Longmaxi formation have been largely neglected.This study focuses on pore structure features of the shales by comparing the structural features of diverse lithofacies and investigating their main controlling factors based on the lithofacies classification of the shale samples from the Longmaxi Formation by means of low pressure N₂/CO₂ gas adsorption, high pressure mercury intrusion, porosity measurement, XRD analyses, FE-SEM and so on.The results show that the organic-rich shales in the eastern Sichuan Basin can be divided to silica-rich argillaceous, mixed argillaceous/siliceous and clay-rich siliceous lithofacies with a porosity ranging from 2.62% to 5.65%.Pore volume of the shale reservoirs is primarily contributed by mesopores, accounting for 50% to 60% of the total, followed by micropores and macropores, accounting for 15% to 20% of the total; while the total specific surface area is mainly contributed by micropores and mesopores, accounting for 70% and 30% of total respectively.The pore development is chiefly controlled by the abundance of organic matters instead of the clay mineral content.Shale with high abundance of organic matters may contain less pores as it could not withstand intense compaction with its soft matrix.The organic-rich shale of silica-rich argillaceous and mixed argillaceous/siliceous lithofacies is high in porosity and shares the similar pore structure with most of the clay-rich siliceous shale, suggesting that the silica-rich argillaceous and mixed argillaceous/siliceous shales can also generate certain amount of nano-scaled pores for shale gas storage.

Differences and controlling factors of Changxing Formation reefs of the Permian in the Sichuan Basin

Deqin Ma, Jingchun Tian, Xiaobing Lin, Long Wen, Liang Xu

2020, 41(6):  1176-1187.  doi:10.11743/ogg20200606

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The development characteristics of the reefs in the Permian Changxing Formation in the Sichuan Basin are systematically studied to determine the differences of the reefs developed in the same formation of different plays through observation of outcrops and cores as well as experiments.The results show that the reefs from different plays vary in the development stage from nil to as much as four stages of development; in the completeness of reef cycles, including the differences in cycles of the same location but of different stages or the same cycle but of different locations; in lithofacies and biological assemblages; and in reef spatial distribution, including a banded distribution of multiple rows, dispersed distribution, single-row distribution and ring distribution.Based on the results, we proposed four factors controlling the reef development, i.e., the palaeogeomorphology determines the location and morphology; the palaeoenvironment controls the development stages and the integrity; the palaeobathymetry (sea-level changes) controls the reef assemblages and cyclicity; and the palaeontology controls the reef composition and integrity.

Development patterns of fractures in carbonate reservoirs in the 2^nd member of Jialingjiang Formation, Puguang area, Sichuan Basin

Kewei Zu, Lingxiao Fan, Bo Wang, Dongsheng Cao, Cong Guan, Zhongchao Li, Xiushen Cheng

2020, 41(6):  1188-1196.  doi:10.11743/ogg20200607

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The parameter characteristics, development pattern and controlling factors of fractures in carbonate reservoirs in the second member of the Jialingjiang Formation (Jia 2 member) in the Puguang area, Sichuan Basin, are analyzed through an integrated study of outcrop, core and thin section observations as well as logging data of the member.The results show that the member contains 4 sets of well-developed fractures of NE-SW-, E-W-, N-S- and NW-SE-trending.The dominant fractures of NE-SW strike are mainly those with a high dip-angle and an aperture normally less than 300 μm.The porosity and permeability calculation shows that the fractures serve as seepage channels rather than reservoiring space.Vertically, the fractures are mainly developed in the dolomite underlying the gyprock in each of the three sub-members, of which the middle sub-member has the most developed fractures.Factors such as the structure, rock mechanical stratigraphic thickness, lithology and diagenesis, control the development of the fractures.The present major principal stress is measured to be nearly E-W orientied, making the E-W striking fractures the most prone to be initiated as the chief flow channels in exploitation, and the NE-SW striking fractures of a preferred direction more likely to form high-permeability zones.

Alluvial depositional system and its controlling effect on hydrocarbon accumulation of the Triassic in the Baikouquan area, northwestern Junggar Basin

Guosheng Qin, Cunyou Zou, Lingbin Lai, Liang Zhao, Haibin Su

2020, 41(6):  1197-1211.  doi:10.11743/ogg20200608

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Alluvial depositional systems, known for their hydrocarbon potential, are mostly developed in basin-range coupling zones.Studying the features of the systems is of great theoretical and practical significance to revealing the coupling relationship between basins and mountains as well as their influence upon hydrocarbon accumulation.Based on high-resolution seismic data, logging and drilling data and core analyses, we studied the Triassic alluvial depositional system in the Baikouquan area of northwestern Junggar Basin and constructed sequence stratigraphic framework to illustrate its facies, distribution and controlling factors.The hydrocarbon accumulation patterns under the control of the system and framework is thereby explored.The research shows that (1) The Triassic in the Baikouquan area is a complete set of second-order sequence, which, according to sedimentary characteristics, can be subdivided into three third-order sequences:the lower third-order sequence (TSQ1) dominated by lowstand system tract in the Baikouquan and Lower Karamay Formations (except for S6 sandbodies); the middle third-order sequence (TSQ2) dominated by lowstand and highstand system tracts in the S6 sandbodies and Upper Karamay Formation; the upper third-order sequence (TSQ3) dominated by transgressive and highstand system tracts in the Baijiantan Formation.(2) Alluvial fan and fan delta are the main sedimentary facies associated with the braided river delta and lacustrine facies.TSQ1, developed in low lake level stage, contains extensive superimposed transgressive alluvial fans.TSQ2 developed with rising lake level contains fan deltas.TSQ3 contains shore to semi-deep lacustrine facies formed during an early stage when lake level rose rapidly to the maximum and braided river delta facies formed during a later stage when lake level dropped.(3) The sequence and sedimentary characteristics of the Triassic system are in good coupling relationship with hydrocarbon accumulation patterns.Massive near-provenance sandy conglomerates of alluvial fan facies are developed in TSQ1 and, with the convenience of migrating along and being favorably blocked (at a later stage) by nearby faults close to source rocks, they turned readily into high-quality tectonic-lithologic reservoirs.TSQ2 and TSQ3 develop large-scale fan delta and braided river delta facies with distributary channels containing high-quality reservoirs and slopes that are far from faults close to source rocks but favorably sealed by differential depositional environment to develop large scale lithologic reservoirs.

Characterization and effectiveness of natural fractures in deep tight sandstones at the south margin of the Junggar Basin, northwestern China

Zhe Mao, Lianbo Zeng, Guoping Liu, Zhiyong Gao, He Tian, Qing Liao, Yunzhao Zhang

2020, 41(6):  1212-1221.  doi:10.11743/ogg20200609

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The Jurassic tight sandstones at the south margin of the Junggar Basin are characterized by great burial depth (more than 4 500 m), poor physical properties and natural fractures that serve as the dominant storage space and percolation channels for hydrocarbon.A study on the characteristics, controlling factors and effectiveness of the fractures is carried out with field outcrop observation, core and thin section data analyses as well as experimental results.The result shows that high-angle structural fractures dominate the sandstones, followed by diagenetic fractures and fractures related to overpressure.The fractures are mostly NNE-SSW-, NNW-SSE-, NEE-SWW- and NE-SW-trending, but NNW-SSE-trending fractures are rarely seen in the middle of the margin and density goes down from east to west.The distribution and formation of the fractures are controlled by stress field, tectonic movement, lithology, layer thickness and reservoir heterogeneity, while the permeability of the fractures is related to fluid activities, overpressure and present in-situ stress.The results also indicate that more than 85% of the fractures in the study area are effective.The high-pressure percolation experiment demonstrates a negative power exponent decrease of the fracture effectiveness with increasing confining pressure.However, the fracture permeability decreases differently under different confining pressure ranges.It decreases rapidly with the increase of the confining pressure less than 15 MPa (at a burial depth of over 1 000 m).The reduction slows down when the pressure exceeds 15 MPa.And at a confining pressure of 65 MPa (equal to the maximum experimental axial pressure of 115 MPa or a burial depth of more than 8 000 m), the permeability stays at 22.5×10^-3 μm².Therefore, natural fractures are still the effective storage space and seepage channels even in deep formations, where they serve to improve physical properties and indicate high-quality deep reservoirs.

Horizontal fractures of the Cenozoic in western Qaidam Basin and their tectonic implication

Jian Li, Lianbo Zeng, Yu Lin, Guoping Liu, Dongsheng Cao, Zhaosheng Wang

2020, 41(6):  1222-1232.  doi:10.11743/ogg20200610

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Fractures in rocks record critical information of crustal tectonic evolution.Outcrop, core and thin section observations show the Cenozoic mudstone of western Qaidam Basin is abundant in open horizontal fractures with rough surface and gypsum fill.These fractures are mainly curve-shaped and occasionally straight in geometry.T-shaped intersections probably formed by the intense interaction between adjacent curved horizontal fractures are observed.The aperture of the fractures mainly ranges from 1 to 10 mm with the maximum value of 30 mm.Both the scale and linear density of the fractures reduce with the decrease of erosional quantity and increase of burial depth.Furthermore, the fractures are restricted in the hinge zone of intensively denuded anticlines.All evidences above indicate that the fractures are linked to the vertical extension induced by residual stress during a rapid uplift and erosion of strata, and probably formed after a tectonic compression as they are observed to incise most early-formed vertical fractures.Given the electron spin resonance (ESR) spectroscopy dating data of gypsum, the generation of horizontal fractures mainly includes two stages:the first stage occurred at about 1.8Ma and the second 0.3Ma.The fractures formed at the second stage are much larger in scale and higher in intensity compared with those at the first stage.The initial driving force for the formation of the fractures calculated based on crack strain indicates that the erosional volume at the second stage is 2-3 times more than that at the first stage.Evidences also reveal that impulse compressional uplift and erosion activities in the western Qaidam Basin occurred during the Quaternary with an ever-growing tendency in intensity, indicating a progressively increasing episodic tectonic activities in the Tibet Plateau since the Quaternary.

Depositional characteristics of tidal channel facies in carbonate ramp of the Cretaceous Mishrif Formation in southern Iraq

Xianyu Mao, Benbiao Song, Rubing Han, Changbing Tian, Baozhu Li, Haiqiang Song

2020, 41(6):  1233-1243, 1256.  doi:10.11743/ogg20200611

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The Cretaceous Mishrif Formation is a major carbonate pay zone in southern Iraq and characterized by typical carbonate ramp deposition, in which high-energy deposits of shoal facies serve to develop the best reservoirs.Further analysis of data from oilfields in southern Iraq reveals high-quality reservoirs in tidal channels of the Mishrif Formation that were previously mistaken for shoal facies.An integrated analysis of cores, casting thin sections, log and seismic data confirms that these reservoirs are indeed of tidal channel facies in lagoon environment.The tidal channel facies is widely distributed as a representative sedimentary subfacies in the area.The sediments of the facies contain grains of good sorting and rounding, and well-developed beddings with grain size showing upward positive rhythmic or homogeneous characteristics, corresponding to "bell-" or "box-shaped" log and seismic responses of weak peak interlayer.On a map view, the facies shows a banded N-SW-trending distribution characterized by an overall shifting from northeast to southwest.This study reveals that large-scale deposits of tidal channel facies are also developed in carbonate strata, a new founding that may serve as an important supplement to the sedimentary model of carbonate ramps.The understanding of carbonate ramps of tidal channel facies also sheds light on reservoir prediction and thereby lays a geological foundation for the design and adjustment of development schemes.

Sedimentary system of the Cretaceous terrigenous clastics and its controlling factors in Senegal Basin, northern West Africa

Yue Gong, Zhiqiang Feng, Changwu Wu, Naxin Tian, Tianbi Ma, Dapeng Wang, Chongzhi Tao, Weiyuan Gao

2020, 41(6):  1244-1256.  doi:10.11743/ogg20200612

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The Cretaceous system with its extensive shelf-edge deltas and slope fans in the Senegal Basin is one of the most active oil and gas exploration areas in the world.This study systematically explores the sequence framework and sedimentary-geomorphic evolution of the shelf-edge slope zone in the basin, and their responses to the tectonic, sea level and sedimentary supply variations based on the analysis of seismic facies and well data.The results show that the Cretaceous sedimentary system could be divided into two composite sequences (CS1 and CS2) separated by the regional unconformities of the Late Aptian and Late Cenomanian.The two sequences are subdivided into eight third-order sequences.The shelf-edge delta and slope fan facies with a source-to-sink relationship are identified.Three sedimentary subfacies are recognized in the deltas according to seismic facies, namely the delta plain, delta front and pro-delta; and four sedimentary units are identified in the slope fans, namely the landslide debris flow lobe, erosion-filling channel, delta-front fan lobe, and distal fan lobe.Three evolutionary stages are determined according to the evolutionary traits of the slope fan (from slope toe stage to erosional and wide and gentle stages).The deposition distribution of the Cretaceous is closely related to provenance supply, paleogeomorphology and eustatic fluctuation at different periods.The locations of the slope fans and the later filling in the deltas were once conditioned by paleogeomorphology.Sea level changes and provenance supply are the major factors controlling the shape and advancement of the deltas and slope fans.Regional tectonic events including the continuous uplift of the Mauritanides in West Africa, the expansion of mid-Atlantic seafloor, and the tilting of continental margin in the Early Cretaceous have changed the provenance supply and paleomorphology of the basin.The Cretaceous clastic sedimentary system with delta-slope fan facies developed on the shelf edge in the Senegal Basin is thus considered the most important target for oil and gas exploration in the study area.

Methods and Technologies

Research on overall recovery rate variations of dynamically changing OOIP

Bingyu Ji, Youqi Wang, Li Zhang

2020, 41(6):  1257-1262.  doi:10.11743/ogg20200613

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With different types of oil reservoirs being put into development in a proper order according to their respective characteristics, operators may be rewarded with more reserves in a given field.However, with reservoir combinations varying, the overall recovery rates of the field change as well.An ordinary differential equation with reserve as independent variable is established to characterize the changing trend of overall recovery rates with increasing reserves and to quantitatively analyze the overall recovery rate changes of Sinopec's reserves that had been successively put into development (or already under development) from 2011 to 2018.The results show that the relationship between the overall recovery rate and reserve increase can be simplified as the total versus the incremental or the remaining.The main factors influencing the overall recovery rate are the quality and proportion of reserve of a certain reservoir in the whole context.The overall recovery rate of a given field is generally decreasing as more and more hard-to-get reserves are put into development.Following the analysis of the recovery rates of various oil reservoir combinations operated by Sinopec and the factors that influence the rate changes, we propose that future EOR study should be focused on improving the efficiency of water flooding and thermal EOR, expanding the application of chemical flooding, gas injection and microbial recovery, and exploring the possibilities of developing innovative EOR technologies.

Fracture identification and evaluation based on multi-pole acoustic logging

Xiaohua Che, Teng Zhao, Wenxiao Qiao, Wenya Lyu, Jianming Fan

2020, 41(6):  1263-1272.  doi:10.11743/ogg20200614

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Multi-pole acoustic logging is widely used in oilfields, especially for stratigraphic fracture assessment and analysis.The study briefly introduces the research status-quo of multi-pole acoustic logging in fracture identification both at home and abroad, and briefs on the currently new methods to evaluate fractures with multi-pole acoustic waveform data.Taking the field multi-pole acoustic waveform data of the drilling sector X in the Ordos Basin as a case study, we determine the fracture dip angle by compressional to shear slowness ratio, and the fracture dip angle and its validity by mode wave attenuation in boreholes.Furthermore, the Stoneley wave reflection coefficient is used to characterize the fracture locations.The intensity of fracture development is estimated by the shear wave slowness anisotropy and difference between the fast and slow shear wave spectrums.The fracture strike is assessed by the fast shear azimuth.In addition, the field electrical imaging log data are applied to compare and verify those fracture measurement methods.The advantages for and interference factors to these methods are also summarized.In all, an integration of multiple methods can certainly facilitate us to obtain more fracture parameters, avoiding some multi-solution problems of a single method, and thus enhancing the accuracy and reliability of fracture assessment based on multi-pole acoustic waveform data.

Petrophysical modeling of horizontal bedding-parallel fractures and its seismic response characteristics

Shuangquan Chen, Qingliang Zhong, Zhongping Li, Min Zhang, Xin Zhao, Xiangyang Li

2020, 41(6):  1273-1281, 1287.  doi:10.11743/ogg20200615

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Petrophysical modeling of fractures and its seismic response characterisitics serve as an important fundation for the fractured reservoir prediction using seismic data, for which we may propose effective seismic inversion and reservoir characterizing methods.With regard to the horizontal bedding-parallel fractures in unconventional shale oil and gas reservoirs, we conducted a study on the petrophysical modeling and its seismic response characteristics.We obtained the rock background media by integrating non-clay and clay minerals, pores and fluids, using actual sample testing and well-logging data, also adopting both the Voigt-Reuss-Hill (VRH) method and self-consistent approximation (SCA) theory.Combined with the information of actual fracture occurence and growth patterns, we estalished the petrophysical modeling of horizontal bedding-parallel fractures based on the Chapman's petrophysical modeling of multi-scale fractures.Finally, the seismic responses were generated using propogator matrix modeling.In combining the above-mentioned test data and the field data, we proposed a workflow of petrophysical modeling of horizontal bedding-parallel fractures based on the petrophysical model of multi-scale fractures, and applied it to the shale reservoirs in the Jianghan oilfield.The forward modeling results show that the horizontal bedding-parallel fractures were well developed in the shale reservoirs, and the seismic responses are significantly frequency-dependent.Meanwhile, the fracture length and density, major target parameters for seismic prediction of horizontal bedding-parallel fractures, are the most important parameters inducing seismic anisotropy.

New equations for characterizing water flooding in ultra-high water-cut oilfields

Yingsheng Wang, Chengfang Shi, Jiqiang Wang

2020, 41(6):  1282-1287.  doi:10.11743/ogg20200616

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Many oil reservoirs stimulated by water flooding in China have entered the ultra-high water-cut stage.Using the relative permeability ratio versus water saturation curve in the performance prediction of these reservoirs often yields up-warping curves and misleading results.Based on a fitting analysis of the up-warping curves of different oilfields, this study obtained a new expression for the relationship between relative permeability ratio and water saturation.New equations were then deduced to characterize the performance of high water-cut reservoirs.Applications of the equations to oilfields verified their effectiveness in the production prediction of ultra-high water-cut reservoirs.

Evaluation of fracture networks along fractured horizontal wells in tight oil reservoirs:A case study of Jimusar oilfield in the Junggar Basin

Zhiming Chen, Haoshu Chen, Xinwei Liao, Lianbo Zeng, Biao Zhou

2020, 41(6):  1288-1298.  doi:10.11743/ogg20200617

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Evaluation of fracture-network systems along fractured horizontal wells is vital to an efficient development of tight-oil reservoirs.Given the lack of efficient evaluation means, we propose a method based on the dynamic inversion theory for the evaluation of fracture networks along fractured horizontal wells in tight-oil reservoirs.To begin with, a mathematical model of well testing that takes into consideration the nonhomogeneous and insufficient fluid supply of the networks is developed based on seepage activities and fracture network geometry.The bottom pressure of wells is obtained through an analytical method from the mathematical model and then used to establish a method for evaluating the fracture-networks.Subsequently, a field application in Jimusar tight oil reservoirs in the Junggar Basin is performed to prove the reliability of the method.The results show that the flow stages in the fracture networks of horizontal wells in the reservoirs involve the wellbore storage and skin effects, fracture bilinear flow, formation linear flow as well as fluid channeling, linear and quasi-stable flow in stimulated areas.It is also found that after fracturing, networks composed of major hydraulic fractures with a half-length of 135 m and a conductivity of 118.87×10^-3 μm² are generated near wellbores.The storability of the minor fracture networks ranges between 6.30% and 17.99%, and the permeability of the stimulated areas is 100.8×10^-3 μm².This study provides a theoretical basis for research works or operations such as reservoir parameter inversion, fracturing evaluation and dynamic monitoring of tight oil reservoirs in the Junggar Basin.

Prediction of fractures in tight gas reservoirs based on likelihood attribute —A case study of the 2^nd member of Xujiahe Formation in Xinchang area, Western Sichuan Depression, Sichuan Basin

Meng Li, Xiaofei Shang, Huawei Zhao, Shuang Wu, Taizhong Duan

2020, 41(6):  1299-1309.  doi:10.11743/ogg20200618

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Traditional fracture prediction methods based on seismic attributes fail to meet the demand for high-precision prediction of fractures of different scales in the exploration and development of tight sandstone gas reservoirs.By introducing the likelihood attribute into the identification of fractures in tight sandstone gas reservoirs in the Xujiahe Formation, Sichuan Basin, a seismic prediction method for fractures based on likelihood and derived attributes is established.The Otsu threshold segmentation method and constraints from image log interpretation are also employed to classify the reservoir space into fault zones, fracture zones and underdeveloped fracture zones and to perform a fine predication of fractures in the second member of Xujiahe Formation (Xu 2 member) in Xinchang area.Results show that the thinned likelihood attribute can reveal the most possible fracturing locations and probabilities.The fracture density reveals the fracturing intensity, which can be used to predict oil/gas production of a certain location.The fracture prediction based on likelihood attribute has effectively improved the seismic prediction accuracy of tight gas reservoirs in the Xu 2 member in the Xinchang area, and is of referential value to the prediction of other fractured reservoirs.

Variation in liquid hydrocarbon content during thermal simulation and its influence on physical property of shale

Mo Deng, Xinguo Duan, Changbo Zhai, Shengxiang Long, Zhenheng Yang, Lunju Zheng, Zhangchang Li, Taotao Cao

2020, 41(6):  1310-1320.  doi:10.11743/ogg20200619

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In the process of thermal simulation, the changes of liquid hydrocarbon content and occurrence mode are important to the in-depth study of pore evolution and shale reservoir characterization.A thermal simulation experiment of semi-closed system was conducted on the low mature Dalong Formation shale from Shangsi section, Guangyuan area, Northwestern Sichuan Basin.The original shales and thermally simulated samples were subjected to argon ion milling-scanning electron microscopy (SEM) observation.The simulated samples and their extracted samples to low temperature nitrogen adsorption experiment.The results show that organic pores are not well developed in the original Dalong Formation shale.With the increase of temperature in thermal simulation, organic pores begin to develop with increasing number and pore size.In addition, the specific surface area and pore volume also increase accordingly, and they are in a good linear positive correlation with the temperature in thermal simulation.However, there is no significant change in the mesopore and macropore volumes with the temperature increase.On the other hand, a positive correlation is suggested between TOC consumption and specific surface area, pore volume, indicating a significant increase of the number of micro-pores during the transformation from organic matter to hydrocarbon.The SEM observation revealed that liquid hydrocarbon mainly exists within shale inter-crystalline pores and organic pores, and its content is started with a quick leap but is followed by a sharp drop with temperature increase, reaching a peak at a thermal simulation temperature of 325 ℃ to 340 ℃, but almost drop to zero at a temperature of 450 ℃ or higher.After liquid hydrocarbon extracting, nitrogen adsorption capacity of the samples is generally enhanced.The samples' pore size distribution is single peaked with a peak within a pore size range of 14.36-23.56 nm, while for the liquid hydrocarbon extracted samples their peak pore size distribution moves to smaller pores of 12.06-22 nm.The specific surface area, micro-pore and mesopore volumes of the extracted samples increase significantly compared to those of the original samples in thermal simulation.The correlation between thermal simulation temperature and specific surface area, micropore volume becomes better for extracted samples, reflecting that the liquid hydrocarbon mainly exists in shale micro-pores and some mesopores.