石油实验地质

2020, 42(1): .

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Abstract:

Research progress on marine oil and gas accumulation in Tarim Basin

GU Yi, HUANG Jiwen, JIA Cunshan, SHAO Zhibing, SUN Yongge, LU Qinghua

2020, 42(1): 1-12. doi: 10.11781/sysydz202001001

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In recent years, great achievements have been made in the exploration of ultra-deep marine oil and gas in the Tarim Basin. New oil and gas discoveries have been achieved in the Shunbei Ordovician, Tazhong Cambrian and Tahe deep strata, which provide abundant basic data for studying the marine oil and gas accumulation in the Tarim Basin. The marine oil and gas in the Tarim Basin are mainly distributed in the platform-basin area. There are various types of reservoirs, and the physical properties of crude oil vary greatly, showing the complexity of hydrocarbon accumulation. Through the analysis of a large number of samples, simulation experiments and extensive geology and geochemistry analysis, combined with the research results of tectonic evolution, sequence stratigraphy, sedimentary facies and sedimentary environments, some significant progress has been achieved such as the distribution and evolution of source rocks, oil and gas geochemistry characteristics, and the distribution characteristics of marine oil and gas reservoirs. The following achievements have been made: 1) clarification that the marine oil and gas in the Tarim platform-basin area mainly come from the Lower Cambrian-Middle/Lower Ordovician source rocks formed under strongly reducing environments, especially the Lower Cambrian Yuertusi Formation in the platform-basin. Two alterations types of ultra-deep marine reservoirs, namely, TSR and thermal cracking are defined, and the corresponding identification indicators are proposed. 2) by establishing the sedimentary development mode of the gentle slope-type high-quality Yuertusi source rocks, through well-seismic calibration, forward modeling, regional survey line interpretation of seismic facies, 3D area attribute analysis and seismic inversion, the distribution of source rocks in the Yuertusi Formation may be predicted, and their evolution characteristics clarified: the "high-pressure hydrocarbon generation evolution inhibition mode" under the long-term low geothermal background since the Yanshan period has delayed the thermal evolution of Shuntuoguole low uplift Cambrian source rocks, and the Shuntuoguole area still has the formation conditions of late high-maturity liquid hydrocarbon. 3) by comparing the hydrocarbon accumulation characteristics of the platform-basin area, the Ordovician oil and gas distribution characteristics have been clarified, further delineating the Cambrian Yuertusi in situ source rocks there, and identification of the light oil-gas reservoirs matching with the active strike-slip faults in the late Yanshan period and charged by the late hydrocarbon supply, which provide an key direction for oil and gas exploration in the ultra-deep carbonate rocks of the Tarim platform-basin area.

Discovery and significance of subtle buried hills in Jiyang Depression, Bohai Bay Basin

MA Lichi, WANG Yongshi, JING Anyu

2020, 42(1): 13-18. doi: 10.11781/sysydz202001013

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The exploration of carbonate buried-hills in the Lower Paleozoic in the Jiyang Depression of the Bohai Bay Basin are at a minimum now, and the exploration targets are not clear. Hydrocarbon accumulation conditions were analyzed, especially the effectiveness of traps, which broke the shackles of traditional accumulation models and achieved exploration success. Three new buried-hill reservoir models have been discovered, namely the Chengbei 313 negative structure, the Chengbei Guxie 14 slope, and the Chengjiazhuang laterally adjacent high-permeability reservoirs. These three new models make the buried-hill negative structure, the slope zone with poor trap effectiveness, and the laterally unblocked buried hill fault blocks that were considered to have no exploration potential earlier become favorable exploration targets. The effectiveness of traps was analyzed from the aspects of fault activity characteristics. At the same time, a development model of 'sand-like mudstone' buried hill reservoirs was provided, which provided a new idea for the effectiveness analysis of buried hill traps.

Formation mechanism of favorable reservoirs in red beds in lower submember of fourth member of Shahejie Formation, Bonan Subsag, Jiyang Depression, Bohai Bay Basin

MENG Tao

2020, 42(1): 19-27. doi: 10.11781/sysydz202001019

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The red beds in the lower submember of the fourth member of Shahejie Formation (Es₄) in the Bonan Subsag of the Jiyang Depression of the Bohai Bay Basin have undergone a long period of sedimentation and diagenesis. The mechanism of primary pore retention and the evolution constraints of secondary pores are not clear, which restricts exploration progress. The controlling factors of favorable reservoirs in the red beds were analyzed by means of core observation, casting thin section identification and scanning electron microscopy and combined with reservoir characteristics analysis. The formation mechanism of the favorable reservoirs was summarized, and their distribution was also predicted. There are two major sedimentary systems in the red bed sediments of the lower Es₄ submember of Bonan Subsag, including alluvial fan-braided river-braided river delta-lake and fan delta-lake. Sandstones are mainly lithic feldspars. Reservoir porosity is composed of residual primary pores, secondary dissolution pores and fractures. Reservoir physical properties are poor. The reservoir belongs to the category of ultra-low porosity and ultra-low permeability. Under the influence of mechanical compaction and the alternation of alkali and acid fluids, the reservoir porosity in the study area experienced three stages: primary pore retention, secondary pore formation and reservoir densification. Burial depth and favorable facies zones determine the preservation degree of primary pores, while organic acid, abnormally high pressure in overlying strata and fracture distribution determine the degree of secondary pore development. The favorable reservoirs with primary pore development are fan-terminal reservoirs of alluvial fan buried less than 3 000 m, which are distributed as belts on the southern basin margin. The favorable reservoirs with secondary pore development are braided river and braided river delta reservoirs with pressure coefficient greater than 1.2 in the upper submember of Es₄ and fault system develop in the lower submember of Es₄, which are distributed in sag zones and show strip-like and overlapping sheet distribution.

Palaeoclimate evolution and sequence stratigraphy during Pliocene Shizigou stage, Qaidam Basin

LI Qingshan, GUO Shaobin, HOU Zesheng, WANG Bo

2020, 42(1): 28-36. doi: 10.11781/sysydz202001028

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The Qaidam Basin is a large transpressional Mesozoic to Cenozoic basin in the Tibet Plateau, West China. Since the Indosinian Movement, it has been in the subsidence stage and more than 3 trillion cubic meters of natural gas accumulated at the same time. The palaeoclimate evolution during the Pliocene Shizigou stage not only controlled sequence stratigraphy development and evolution, but also worked as a key restraining factor for the largest biogas resource in the world. A case study was made in the well Qijia 1, which is the longest cored well in the Qaidam Basin. The palaeoclimate evolution during the Shizigou stage was reconstructed by using geochemistry methods, including the contents of chloride ion, trace elements and TOC, combined with core data, well logging, paleontology data and sequence stratigraphy. The contents of Sr/Ba and Sr/Ca have a positive correlation with chloride ion, which means that the values of Sr/Ba and Sr/Ca are high in an arid environment. But the contents of Rb/Sr and TOC have a negative correlation with chloride ion, which means that the values of Rb/Sr and TOC are low in an arid environment. The palaeoclimate during the Shizigou stage came through an arid-humid-arid evolution and the water body is brackish water. Based on sequence stratigraphy, five sub-palaeoclimate cycles were recognized for the first time. The palaeoclimate evolution and sequence evolution have the same cyclicity, which shows the controlling function of palaeoclimate.

Main controlling factors of shale gas enrichment and high yield: a case study of Wufeng-Longmaxi formations in Fuling area, Sichuan Basin

FANG Dongliang, MENG Zhiyong

2020, 42(1): 37-41. doi: 10.11781/sysydz202001037

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The controlling factors of shale gas enrichment and yield were discussed based on core observation, geochemical analysis, logging and seismic data of marine shale collected from the Wufeng-Longmaxi formations in the Fuling area of Sichuan Basin. Total organic carbon content, micro-to nano-scale pores and preservation conditions are the main controlling factors for shale gas enrichment. The total organic carbon content is not only an important parameter for evaluating original shale quality, but also affects micro-to nano-scale pore development. The preservation condition is important for shale gas enrichment. The high yield of shale gas is affected by brittle mineral content, burial depth, structural morphology and fractures. The higher the brittle mineral content, the better the compressibility of shale and the better the effect of fracturing. In addition, burial depth and structure features have great effect on crustal stress, and thus have significant influence on fracturing. Natural fracture development leads to directional pressure relief during fracturing, and it is difficult to form an effective and complex permeability mesh.

Diagenetic facies of carbonate rocks in Yijianfang Formation, Shunbei area, Tarim Basin

CHENG Chuanjie, YU Bingsong, WU Chongyang, YANG Weili, RUAN Zhuang

2020, 42(1): 42-52. doi: 10.11781/sysydz202001042

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The diagenetic facies of the Ordovician Yijianfang Formation in the Shunbei area of the Tarim Basin was analyzed using drilling core description, thin section observation, as well as logging trace and seismic data analysis. There are five diagenetic facies types: dissolution, dolomitization, fracture, cementation and hydrothermal facies, which were further divided into eight subfacies: atmospheric freshwater dissolution, burial dissolution, fracture dissolution, penecontemporaneous dolomitization, burial dolomitization, subsea cementation, freshwater cementation, and burial cementation. Five composite diagenetic facies were identified: cementation-hydrothermal, fracture-dissolution, fracture-cementation, fracture-hydrothermal, and dolomitization-cementation-hydrothermal facies. The subsea cementation subfacies was developed in the low system tract, while the tectonic-hydrothermal and cementation subfacies were developed in the high system tract. In intraplatform beach sediments, atmospheric freshwater dissolution and atmospheric freshwater cementation subfacies, and a small amount of tectonic-hydrothermal subfacies developed. In interstitial marine sediments, there developed burial dolomitization, dissolution and cementation subfacies. In intraplatform reef sediments, atmospheric freshwater dissolution and atmospheric freshwater cementation subfacies occur. The diagenetic facies evolution was controlled by tectonics, sedimentary facies and sequence and constrained by point, single well profiles, diagenetic facies connected wells and root mean square amplitude attributes. The distribution of favorable diagenetic facies in the Shunbei area is gradually transitions from the southwest to the northeast.

Occurrence and recoverability of tight oil in Paleogene Funing Formation, Subei Basin

PENG Jinning, QIU Qi, WANG Dongyan, LI Zhiming, ZHU Jianhui, LIANG Shiyou, WU Yingli

2020, 42(1): 53-59. doi: 10.11781/sysydz202001053

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The shale, interlayers and adjacent carbonate rocks and siltstones in the second and fourth members of the Paleogene Funing Formation in the Subei Basin were studied using multi-temperature pyrolysis and NMR. The oil-bearing capacity of shale, interlayers and adjacent tight reservoirs in the Funing Formation and the movability of tight oil were evaluated in combination with with shale oil production data. In the second and fourth members of the Funing Formation, the content of tight oil is generally less than 5.0 mg/g in shale. Adsorption-miscible oil is dominant, and the ratio of which to total retained oil decreases with the increase of burial depth. Light free oil generally has a low content, and the actual movable oil ratio is less than 3%. However, the tight oil content is generally greater than 5 mg/g in mud shale interlayers and adjacent sandstones (oily), dominated by free oil. The light free oil content is generally more than 0.25 mg/g, and the actual movable oil ratio is generally between 4% and 7%, which is close to the 5% recovery ratio in the tight sandstone layers before reconstruction in the middle of Bakken Formation in North America. The movable tight oil mainly exists in fractures in the Funing Formation in the Subei Basin. That is, tectonic fractures are the main host of movable shale oil, and some micro pores (with ramp radius greater than 0.18 μm) work as secondary occurrence porosity. Free oil exceeds adsorbed oil. The initial production of tight oil is high in fissured lacustrine carbonates in the first and third members of the Funing Formation, but the production decreases rapidly with a short production cycle, and the economic recoverability is limited. In contrast, the initial production is lower in the tight interlayer sandstones of the source in the second and fourth members of the Funing Formation, which has a slower decline rate, longer production cycle and better economical recoverability.

Diagenesis and pore evolution of tight sandstone reservoirs in Upper Triassic Bagong Formation, North Qiangtang Depression, Qiangtang Basin

CHENG Leli, YIN Senlin, WAN Youli, WANG Jian, FENG Xinglei, LI Xueren, ZENG Shengqiang

2020, 42(1): 60-68. doi: 10.11781/sysydz202001060

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The diagenesis and pore evolution process of tight sandstone reservoirs in the Upper Triassic Bagong Formation of the North Qiangtang Depression were studied by means of physical properties, casting thin slice, SEM, X-ray-diffraction and fluid inclusion temperature measurement. The compositional maturity and structural maturity of the Bagong sandstones are moderately low. Their physical properties are extremely tight. The main diagenetic effects include compaction, cementation, dissolution and metasomatism. The cement components are mainly siliceous, clay minerals and carbonate minerals, and the dissolution component is feldspar. According to the comprehensive analysis of various characteristics, the shallow buried area near the uplift is in the middle diagenesis stage B, and the deep buried area inside the depression is in the late diagenetic stage. Under the premise of considering the apparent volume change and compaction of rock, a quantitative calculation of pore evolution of different diagenetic facies is carried out. The calculation results show that compaction is the primary cause of reservoir porosity reduction, followed by cementation, while dissolution and the formation of chlorite lining are beneficial to reservoir porosity.

Shale reservoir characteristics of Ordovician Wufeng-Silurian Longmaxi formations in Dangyang synclinorium, Middle Yangtze region

FAN Jiawei, CHEN Kongquan, SHEN Junjun, ZHU Wei, TANG Xiehua, LI Junjun, WANG Pengwan, ZHANG Fang

2020, 42(1): 69-78. doi: 10.11781/sysydz202001069

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The petrological and organic geochemical characteristics, reservoir porosity types and features, and gas-bearing characteristics of organic-rich shale were systematically studied using FIB-SEM, mineral contentanalysis, organic geochemical analysis and low-temperature and low-pressure nitrogen adsorption porosity determination, and drilling data of typical wells in the Dangyang synclinorium. (1) Vertically, shale reservoirs from the Wufeng Formation(O₃w) are quite different from the first section of the first member of Longmaxi Formation (S₁l₁¹). High-quality shale reservoirs are developed from S₁l₁¹⁽¹⁾ to S₁l₁¹⁽²⁾ sublayers, with a high abundance of organic matter (2.45%-6.98%), type Ⅱ₁-Ⅱ₂ organic matter, rather high thermal evolution degree, high brittle mineral content (34.0%-85.5%), low clay mineral content (9.0%-40.3%), and high total gas content (1.76-4.30 m³/t). Organic pores are well developed. In the S₁l₁¹⁽³⁾ sublayer, affected by the intensified Caledonian tectonic activity, terrigenous material input increased, and reservoir quality began to deteriorate. (2) Horizontally, organic-rich shale of the Wufeng-Longmaxi formations in the Dangyang synclinorium become thicker from southeast to northwest, and the reservoir quality becomes better. (3) Shale reservoirs in the S₁l₁¹⁽¹⁾-S₁l₁¹⁽²⁾ sublayers in the study area are the "sweetest" and the "most brittle".However, considering the convenience of real-time monitoring and adjustment of well trajectory during horizontal drilling, the upper and lower half of GR peak in the S₁l₁¹⁽¹⁾ sublayer should be selected as the best horizontal target of horizontal wells.

Seismic sedimentology of lower part of second member of Shanxi Formation in Gaojiahe area, Ordos Basin

LAI Shenghua, BAI Pu, YE Chao, ZHANG Lei, CHI Jing

2020, 42(1): 79-87. doi: 10.11781/sysydz202001079

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The method of using seismic information to study the planar distribution characteristics of sedimentary system is illustrated using the lower part of the second member of the Lower Permian Shanxi Formation in the Gaojiahe 3D area of the Ordos Basin as an example. Firstly, based on rock physical properties, time-frequency scanning technology was used to study the seismic reflection characteristics of coal seams in a 90° phase seismic data volume. Secondly, by designing specific filters, seismic waves were filtered to suppress the influence of coal seams on seismic reflection characteristics. A fine (high-frequency) isochronous stratigraphic framework in the 3D seismic data volume was created by combining high-precision sequence stratigraphy with seismic sedimentology. Finally, combining geological features, logging responses and seismic facies analysis, provided the sedimentary analysis of isochronous stratigraphic slices with different frequencies. Mixed frequency display technology was applied to study the spatial distribution characteristics of sedimentary facies. The distributary channels in the lower delta plain sub-facies of the second member of Shanxi Formation in the Gaojiahe 3D area are mainly represented by three trends: (1) Some show north-south, east-west, and then north-south trends, along S229, S228, S232, S208, Y124 well edge. In these distributary channels, a meandering beach with a certain scale may develop near well S231. (2) Some show a northwest-southeast trend, mainly distributed along wells S212, Y127, and S209; (3) Some show a nearly west trend. A large-scale lateral river migration zone develops along wells S210 and S226.

Characterization of sedimentary and flow characteristics of shallow water delta front sand bodies: Xingshugang Oil Field, Daqing placanticline, Songliao Basin

LÜ Duanchuan, SONG Jinpeng

2020, 42(1): 88-94. doi: 10.11781/sysydz202001088

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The low degree of integration between relative permeability research and the sedimentary characteristics of sand bodies was studied. The sedimentary and flow characteristics of distributary channel microfacies and sheet sand microfacies in shallow water delta front subfacies in the Daqing placanticline of the Songliao Basin were characterized by using core and logging data of continuously cored wells, relative permeability test data, grain size analysis, scanning electron microscopy and mercury injection data under reservoir conditions. The vertical variation of distributary channels and the difference of the positions of the outer edge, middle and inner edge of sheet sand were analyzed. The factors controlling the development degree of distributary channel sand body and sheet sand are the difference of vertical oil-water fluidity and the heterogeneity of horizontal flow capacity, respectively. In the distributary channel microfacies of shallow water delta, the relative permeability varies little; however, the vertical oil-water fluidity makes the bottom more prone to flooding, which is the main factor causing the formation of residual oil between wells. The planar difference of sheet sand sedimentary characteristics makes it easier for the injected water to advance along the outer edge, which is the main factor causing the low recovery of the reserves in the inner edge and the middle.

Petroleum geology and exploration in Levant Basin, Eastern Mediterranean

TIAN Kun, YIN Jinyin, WANG Dapeng, GUO Jinrui, TAO Chongzhi

2020, 42(1): 95-102. doi: 10.11781/sysydz202001095

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This paper analyzes hydrocarbon accumulation conditions, defines hydrocarbon plays and discusses their hydrocarbon accumulation models using geological and geophysical data and an international petroleum exploration and production database, with an approach of integrated geological investigation and play quick analysis. The intention is to identify favorable areas for exploration in the Levant Basin which experienced three main tectonic evolution stages, including rifting, passive continental marginal and tectonic inversion. It can be divided into three plays in Miocene, Pliocene and Mesozoic reservoirs. The Miocene play is the most important. The controlling factors of Miocene play are Oligocene-Miocene biogenic gas, high-quality submarine fan turbidite sand reservoir that related to Palaeo-Nile drainage system, large-scale anticline traps formed during tectonic inversion and Messinian evaporite as a regional caprock. High-quality channel turbidite sand reservoirs related to small-medium sized submarine canyons and short-distance gas migration are key factors that control hydrocarbon accumulation of the Pliocene play. Potential Cretaceous deepwater clastics and Jurassic carbonate build-ups on highs comprise a speculative Mesozoic play in deep water. Three plays are favorable regimes for future exploration, and the Miocene play in deep water and the under-explored Mesozoic regime are of high exploration potential.

Differential hydrocarbon enrichment and controlling factors in passive margin basins of the Arabian Plate

BAI Guoping, NIU Binbin, CHEN Jun, HU Jingjing, MENG Qiuhan, QIU Haihua

2020, 42(1): 103-112. doi: 10.11781/sysydz202001103

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The integrated analyses, classification and comparison of petroleum systems, combined with the latest oil and gas field data from the Middle East and the previous research results, indicate how tectonic-depositional evolution, source rocks and seals, and petroleum resource endowment are inter-linked. The impacts of these factors on the enrichment of petroleum resources could be established. There are four super petroleum systems in the passive margin basins of the Arabian Plate, namely, the intra-craton, the back-arc, the passive margin and the active margin, among which the passive margin and intra-craton super petroleum systems are the most significant. Regionally, oil and gas in the study area are mainly concentrated in the Central Arabian Basin and the Rub' Al Khali Basin. Stratigraphically, oil is mainly reservoired in the Cretaceous and Jurassic whereas the gas in the Permian and Triassic. The diffe-rential enrichment of hydrocarbons is mainly controlled by three factors: the distribution of high-quality effective source rocks and the positive structural trends of basins, which have a dominant control on the regional distribution of oil and gas, and the regional seals, which govern the stratigraphic distribution of oil and gas.

Carbon isotope fractionation characteristics during shale gas release

TAO Cheng, ZHAI Changbo, YU Linjie, SHEN Baojian, WANG Jie, YANG Huamin

2020, 42(1): 113-116. doi: 10.11781/sysydz202001113

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The isotope monitoring of desorption gas from shale cores was carried out at the drill site. Gas is lost during core recovery and thus the isotope variation for the whole process of gas release from shale cores cannot be obtained. A high pressure methane saturation-desorption device was developed and connected to the chromatographic-isotope mass spectrometry system to monitor the carbon isotope change of released CH₄ on-line. The isotopic curves of releaed methane were initially stable, and then tended to become lighter and finally heavier, which was related to the phase transformation and the mixing ratio of free gas and adsorbed gas. Isotopes have potential applications in monitoring shale gas development.

Correlation of oils and source rocks and genesis of high wax oils in Gaoshangpu area, Nanpu Sag, Bohai Bay Basin

DIAO Fan, WANG Jianwei, CHEN Xiaona, WANG Zhengjun, ZHANG Yongchao

2020, 42(1): 117-125. doi: 10.11781/sysydz202001117

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There are significant differences between crude oil properties and enrichment horizon across the Gaoliu Fault in the Gaoshangpu area of the Nanpu Sag.Oils are mainly enriched in the third member of Shahejie Formation (Es₃) to the north of the Gaoliu Fault, and are characterized by a high wax content.However, oils are mainly enriched in the Minghuazhen, Guantao and Dongying formations to the south of the Gaoliu Fault, and are normal crude oils with a low wax content. The biomarkers and compound specific isotopes of crude oils from different layers show that the origin of the high wax content oils in the Es₃ is different from that of the oils to the south of the Gaoliu Fault. The former is derived from the source rocks of the Es₃⁴ and the latter is sourced from the third member of the Dongying Formation (Ed₃) in the Linque Sub-Sag to the south of the Gaoliu Fault. The source rocks of the Es₃⁴ contain abundant terrigenous higher plants and lower hydrobionts, which provide the wax source. The microbe reformation, low thermal evolution degree and abnormal high pressure in the Es₃ are key factors in the formation, migration and preservation of high wax oils.

Mechanism of “high-speed braking” effect on heavy oil formation during hydrocarbon migration: a case study of the eastern part of southern slope of Dongying Sag, Bohai Bay Basin

DU Zhenjing

2020, 42(1): 126-131. doi: 10.11781/sysydz202001126

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The phenomenon of "high-speed braking" occurs due to the accumulation of oil and gas during hydrocarbon migration. Then the macromolecular substances are blocked and cannot pass through, while the small molecules can continue to migrate. The well Wang 146 area is located in the eastern part of the southern slope of the Dongying Sag in the Bohai Bay Basin. The viscosity of crude oil in the fourth member of the Shahejie Formation in this area is higher than that of the Dingjiawuzi structural belt in the lower part and the Bamianhe structural belt in the higher part. The "high-speed braking" effect was used to explain the occurrence of this phenomenon, and the formation mechanism of ultra-heavy oil reservoirs in this area was analyzed. At the same time, the geological conditions for the formation of the "brake effect" were discussed from three aspects: sand body thickness, formation inclination, and the characteristics of abnormal formation pressure. The differences in the main peak carbon, ∑C_21-/∑C₂₂₊, and the degree of crude oil degradation in the three tectonic belts of the study area can be used as favorable geochemical evidence for the formation of heavy oil caused by the "high-speed braking" effect during crude oil migration.

Petroleum accumulation system evaluation of carbonate oil and gas: a case study of Cambrian in Tarim Basin

ZHOU Bo, LI Huili, YUN Jinbiao, XU Zhongmei, FENG Fan

2020, 42(1): 132-138. doi: 10.11781/sysydz202001132

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An evaluation of carbonate oil and gas was carried out based on the petroleum accumulation system theory of a superimposed basin. Considering the evaluation parameters of previous achievements, the hydrocarbon resource, plays, pathway systems and the preservation of the petroleum system were analyzed for carbonate beds in the Tarim Basin. A new evaluation standard was prepared. In this standard, the plays which go through the same tectonic evolution process, and the hydrocarbon resource and pathway system, which provide hydrocarbon for the play, comprise one petroleum accumulation system. In the evaluation of pathways, three parameters, type of migration pathway, hydrocarbon supply mode, and migration distance are chosen. The statistics of migration distance and reservoir numbers showed that migration distance can be divided into four sections, < 10 km, 10-50 km, 50-100 km, > 100 km. Oil and gas accumulation units and basin structural units were both used to divide the oil and gas area, and the uncertainty of geological parameters was also taken into account. The evaluation of the carbonate oil and gas in the Tarim Basin was carried out. The east of the Tabei uplift and the north of the Tazhong uplift belong to class 1, while the Shuntuoguole low uplift, Southwest Depression, south of Tazhong uplift, north of Bachu uplift, west of Tabei uplift belong to class 2.

Three-dimensional simulation of oil distribution during waterflooding in a micrometer-sized pore network system of tight sandstone

MA Yong, ZENG Jianhui, FENG Xiao

2020, 42(1): 139-146. doi: 10.11781/sysydz202001139

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The porosity and permeability of tight oil reservoirs are quite low. The occurrence of oil in tight oil reservoirs, which are composed of a micrometer-sized pore network system, is one of the most important scientific issues to be solved in tight oil research. Oil was removed from two tight sandstone core samples (with diameter 3 mm and 5 mm) which were saturated with KI and oil and monitored by core flooding system using X-ray Micro-CT, to display the occurrence and accumulation characteristics of oil in the micrometer-sized pore network. Pores with radius larger than 10 μm have good connectivity and comprise the dominant pore network system for oil accumulation, while 62.9%-84.1% of the oil accumulates in pores with radius from 10-60 μm. Pores with radius smaller than 10 μm are huge in number; however, most of them are isolated in space, the oil saturation of these pores is low and they only gathered 6.8%-20.0% of oil in tight sandstone. The oil saturation of tight sandstone increases in three steps with pore radius in the range of 10%-40% for pores with radius smaller than 10 μm, 30%-75% for pores with radius 10-60 μm, 40%-75% for pores with radius 60-80 μm. The occurrence of oil in micrometer-sized pore network systems in tight sandstones is controlled by the size, origin and spatial distribution of pores.

Recalculation and understanding of middle and low rank coalbed methane reserves: a case study of Baode Coalbed Methane Field on the eastern edge of Ordos Basin

ZHANG Lei, HAO Shuai, ZHANG Wei, CAO Yimin, SUN Xiaoguang, YIN Siyu, ZHU Wentao, LI Ziling

2020, 42(1): 147-155. doi: 10.11781/sysydz202001147

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The Baode Coalbed Methane Field is located in the northern section of Jinxi Flex Belt on the eastern edge of Ordos Basin. It is a typical coal seam gas field of middle and low ranks. In 2011, the gas field proved 18.363×10⁹ m³ of proven geological reserves and 9.182×10⁹ m³ of technically recoverable reserves. The reserve area has been developed on a large scale for 6 years. The reserve calculation parameters have changed significantly, so it is necessary to reassess the utilization and availability of reserves. In September 2018, we recalculated geological reserves using the volume method and dynamic information by combining reserve specification with the output mechanism and development characteristics of coalbed methane. The production decline method and analogy method were used to recalibrate the recovery rate. Then, the proved reserves submitted in 2011 were recalculated. The proved reserves of coalbed methane increased by 2.986×10⁹ m³ after compounding. The recovery calibration result is 52%, up 2% from 2011. The recoverable reserves of calibration technology were 11.094×10⁹ m³, with an increase of 1.912×10⁹ m³ over 2011. Reserve recalculation focuses on the changes in calculation parameters. In the calculation of technical recoverable reserves and the determination of recovery rate, it is necessary to carry out classification and calculation according to geological conditions in the developed area.

Micropore inhomogeneity of continental shale under different side length and resolution: a case study of Chang 7² shale from well Yaoke 1 in Ordos Basin

SHANG Yanjun, ZHAO Bin, HU Ruilin, SHAO Peng

2020, 42(1): 156-162. doi: 10.11781/sysydz202001156

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Continental shale is different from marine shale due to its inhomogeneity, which is apparent mainly in the inhomogeneity of pore structure. The Upper Triassic Yanchang black shale (Chang 7²) samples were collected from the well Yaoke 1 in the Ordos Basin. Micro and nano CT were used to observe and analyze the pores and cracks of 7 different side lengths (100-700 μm) and 4 different side lengths (10-39 μm) at 1 μm and 65 nm resolutions, respectively. The spatial inhomogeneity index of different side lengths and resolutions based on 3D image reconstruction was established. It was found that the number and volume of pores increased exponentially with the increase of side lengths, while the plane density of the pores decreased with the increase of side lengths. The average length, width and their ratio remained basically unchanged. Coordination number, as an indicator of connectivity, is closely related to the average width of pores.

2020, 42(1): 163-163.

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2020, 42(1): 164-164.

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2020 Vol. 42, No. 1

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