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Table of Content

    28 April 2020, Volume 41 Issue 2
    Previous Issue    Next Issue
    Petroleum Geology
    Formation mechanism of high-quality deep buried-hill reservoir of Archaean metamorphic rocks and its significance in petroleum exploration in Bohai Sea area
    Changgui Xu, Xiaofeng Du, Xiaojian Liu, Wei Xu, Yiwei Hao
    2020, 41(2):  235-247, 294.  doi:10.11743/ogg20200201
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    The weathering crust of deep metamorphic rocks is relatively dense, and the development of fractures is key to reservoir quality.The formation mechanism of high-quality buried-hill reservoir of deep Archaean metamorphic rocks in the BZ 19-6 structure was analyzed through core description, casting thin section observation, microscopic fluorescent analysis of thin section, scanning electron microscopy and conventional physical property measurements.The results show that the Archaean rocks in the BZ 19-6 structure are dominated by gneiss, metamorphic granite and migmatite, in which the high content of felsic minerals with great brittleness is prone to fracture development.Thus, they tend to develop high-quality reservoirs.The fragmentation under continuous deformation and stress makes large-scale fracture zones and stress fragmenting zones developed inside the buried hill, which is the key to the formation of high-quality reservoirs in metamorphic rocks.The weathering resulted in a large number of secondary dissolution pores and dissolution enlarged pores along fractures on top of the buried hill.However, the weathering crust became relatively dense under deep burial.Under the guidance of controlling factors mentioned above, a reservoir distribution pattern of "vertical connectivity, and lateral continuity" is revealed for large-scale deep metamorphic reservoirs of high quality.

    Differential hydrocarbon enrichment of the Paleogene and its main controlling factors in the Bohai Bay Basin
    Youlu Jiang, Shengmin Su, Hua Liu, Yongshi Wang, Xiaojun Cui
    2020, 41(2):  248-258.  doi:10.11743/ogg20200202
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    The differences of hydrocarbon accumulation in distribution horizon and enrichment degree are obvious in a petroliferous basin.Based on previous studies, we discuss the differential hydrocarbon enrichment and its major controlling factors of the Paleogene in various depressions of the Bohai Bay Basin.The results show that the petroliferous depressions can be divided into three patterns in terms of hyrdrocarbon accumulation, namely the enrichment patterns of the Pre-Paleogene, of the Paleogene and of the Neogene, with the second pattern taking the lead.The Paleogene hydrocarbon accumulation is characterized by "rich east but poor west" and "high heterogeneity in vertical distribution"-horizontally speaking, hydrocarbons concentrate in the eastern part (rich in hydrocarbon) of the basin; vertically, they mainly accumulate in source rock sequences and the adjacent Es2 and Es3, and diminish herein upwards and downwards.The diffe-rential hydrocarbon enrichment of the Paleogene in different depressions is jointly controlled by multiple factors:the conditions for hydrocarbon generation are the fundamental one; the differential geothermal fields and source rock thermal evolution are the key to the differential hydrocarbon enrichment of "rich east but poor west"; and the differential hydrocarbon generation potentials of different source rock sequences, major source rock interval, source rock-reservoir-caprock assemblage, and carrier faults, collectively determine the vertical enrichment of hydrocarbons in the basin.

    Quantitative evaluation of hydrocarbon accumulation pattern and the controlling factors in the Neogene of Huanghekou Sag, Bohai Bay Basin
    Haifeng Yang, Changgui Xu, Chengmin Niu, Geng Qian, Zhengyu Li, Yanfei Gao, Zhen Huang
    2020, 41(2):  259-269.  doi:10.11743/ogg20200203
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    The quantitative study on hydrocarbon accumulation has always been a thorny problem in hydrocarbon exploration.In combining with a series of analyses including 3D seismic and logging data, we carry out a comprehensive study focusing on the setting and pattern of, as well as factors controlling hydrocarbon accumulation in the Neogene of Huanghe-kou Sag.The results show that the hydrocarbons mainly enrich in inverted strike-slip and faulted uplift structural belts, demonstrating two distinct accumulation patterns.The hydrocarbon migration of the Neogene in the strike-slip inverted belt is controlled jointly by the activity intensity of source rock-rooted fault and regional seal thickness in the Paleogene; while that of the Neogene in the faulted uplift belt is controlled jointly by the transporting ridges and late faults cutting through the reservoir.Further, the quantitative evaluation model and formulae characterizing the hydrocarbon migration capacity under the two accumulation patterns are established.In addition to the hydrocarbon oil source conditions, the scale of hydrocarbon accumulation is also controlled by the contact area between fault and sand body.The larger the total contact area between sand bodies and source rock-rooted faults, the higher the fill factor of the reservoir will generally be.

    The impact of thermodynamics and kinetics of feldspar dissolution-precipitation on reservoir quality: A case study from the Es3, Bonan Sag, Bohai Bay Basin
    Zhenhuan Shen, Bingsong Yu, Chenyang Bai, Shujun Han, Zhihui Yang, Zhibin Fei
    2020, 41(2):  270-283.  doi:10.11743/ogg20200204
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    Feldspar dissolution along with the formation of secondary pores has a great impact on sandstone reservoir qua-lity.In order to study belts favorable for pore development in the Bonan sag, Bohai Bay Basin, we mainly focused on the research of secondary pores of feldspar in the Es3, by means of thermodynamics and kinetics calculation of feldspar dissolution-precipitation, combined with petrologic characteristics such as thin section observation, porosity and permeability data.The results show that formation water nowadays is favorable for the precipitation of feldspars, with feldspars in some areas having dissolved.According to the horizontal distribution of porosity and the thin section observation under microscope, we may conclude that the areas of better porosity are characterized by K-feldspar dissolution, fast dissolution of anorthite (ΔG < -15 kJ/mol) and slow precipitation of albite (ΔG < 15 kJ/mol).In addition, the reservoir permeability decreases as clay minerals (including kaolinite) precipitate in those secondary pores with feldspar dissolution.Meanwhile the reservoir porosity decrease accelerates significantly when SiO2 (aq) precipitation in the formation water in areas is triggered at a burial depth of over 3 000 m.In all, the feldspar dissolution has a great contribution to the formation of secondary pores in burial.However, the contribution may be compromised if by-products from feldspar dissolution are not removed, and higher clay content also tends to undermine the reservoir permeability.The study is a positive demonstration of a new way to predict reservoir quality by thermodynamics and kinetics models.

    Reservoir characteristics and exploration of the Lower Cambrian shale gas in the Middle-Upper Yangtze area
    Bo Gao, Zhongbao Liu, Zhiguo Shu, Haotian Liu, Ruyue Wang, Zhiguang Jin, Guanping Wang
    2020, 41(2):  284-294.  doi:10.11743/ogg20200205
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    The study aims to clarify the reservoir pore characteristics and the factors influencing the ancient shale sequences in Southern China with the samples taken from the Lower Cambrian shale in the Middle-Upper Yangtze area.An integration of multiple technical methods, including the thin section observation, joint tests of high pressure mercury injection and nitrogen adsorption, argon ion milling-scanning electron microscopy, focused ion beam scanning electron microscopy (FIB-SEM), whole-rock X-ray diffraction analysis is applied to systematically study the structure, types and influential factors of shale pores.Meanwhile, the potential targets for exploration of the Lower Cambrian shale gas are also pointed out based on the characteristics of the shale reservoir and the geological conditions for shale gas generation.It is concluded that the Lower Cambrian in the study area mainly develops three types of organic-rich shale in terms of depositional genesis, namely the extensional-trough, shelf-margin slope, and platform-front slope.The organic-rich shale of the intra-shelf extensional-trough type is dominated by intergranular pores and interlayer pores of clay mineral, followed by organic pores; that of the platform-front slope type mainly develops organic pores and calcite intragranular dissolution pores; while that of the shelf-margin slope type mainly develops organic pores with almost no inorganic mineral pores.As a whole, the pore development in the Lower Cambrian shale is controlled by a variety of factors including the mineral composition of shale, the abundance of organic matter, thermal evolution degree, and preservation conditions.Given the analysis of shale gas preservation conditions and drilling results of exploration wells, it is suggested that we should pay more attention to the distribution of intra-shelf extensional-trough shale in the Lower Cambrian shale gas exploration within the Sichuan Basin, and this is especially true for the organic-rich shale intervals in the upper part of the Qiongzhusi Formation.While as for the outer area of the Sichuan Basin, the organic-rich shale of both the platform-front and the shelf-margin slope types, featuring moderate thermal evolution and relatively good preservation conditions, should be the research focus.

    Microscopic pore structure of Ahe tight sand gas reservoirs of the Low Jurassic in Kuqa Depression and its controls on tight gas enrichment
    Peng Wang, Linghui Sun, He Wang, Zi'an Li
    2020, 41(2):  295-304.  doi:10.11743/ogg20200206
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    Kuqa Depression has been an important region for exploring deep tight sand gas reservoirs in the Tarim Basin during the past few years.The study aims to discuss the micro-structure features of the Ahe tight sandstone reservoirs in the Dibei tight sand gas pool in the Kuqa Depression via reservoir property and inclusion tests, casting thin section observation, MIP(mercury intrusion porosimetry), as well as x-ray micro-CT scanning.What's more, combined with logging interpretation and fluid inclusion data, the controlling effect of microscopic pore structure on tight sand gas enrichment is revealed.The results show that the tight sand reservoirs in the Lower Jurassic Ahe Formation is characterized by a majority of dissolved pores(including intragranular dissolved pores in feldspar, lithic debris, and dissolved pores in cements)and micro-fractures, together with limited residual intergranular pores.The micro-structure of the Ahe sand reservoir pores can be classified into three types.Specifically, type one mainly developed in coarse-grained sandstones is characterized by capillary bundle-shaped pore system, with poor pore throat sorting, large pore throat radius but low pore-throat ratio, and relatively high permeability; type two mainly occurring in the coarse-to-fine grained sandstones is characterized ink-bottle-shaped pore system with relatively poor pore throat sorting, pore throat radius smaller than that of type one mentioned above but large pore-throat ratio; type three mainly appearing in fine-to-silty sandstone also has ink-bottle-shaped pore throat system with relatively good pore throat sorting and pore throat radius smaller than that of type two and low permeability.Type one pore structure can serve as the pathway for tight gas migration, type two is favorable for tight sand gas enrichment, while type three reservoir has no gas charging.

    Characteristics of basement reservoirs and setting for natural gas accumulation in Jianbei slope, Qaidam Basin
    Xiaoqin Jiao, Huapeng Niu, Qingbin Xie, Yongshu Zhang, Junwei Li, Zhixiong Wu, Bo Wang, Xin Li
    2020, 41(2):  305-315.  doi:10.11743/ogg20200207
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    Jianbei slope is one of the key areas for natural gas exploration in the eastern segment of the Altun Piedmont, Qaidam Basin, but the analysis of developing characteristics and gas accumulation conditions of the basement reservoirs in this area is still rarely seen.Based on observation of cores and thin sections, combined with major element analysis, XRD, SEM, MIP(mercury intrusion porosimetry)and log-seismic data analysis, we analyzed the developing characteristics of basement reservoirs and the favorable conditions for natural gas accumulation in Jianbei slope, Qaidam Basin.The results show that the basement reservoirs in the study area are dominated by granodiorite, granite and schist.The reservoirs of weathering crust type are developed there, with the semi-weathering crust reservoirs being the best in porosity and per-meability.The reservoir space is mainly matrix micropores, dissolved pores and cracks, with a reservoir porosity ranging between 2.23% and 3.77% and an average permeability of 0.06mD.So the reservoirs are mainly Type Ⅱ reservoirs of medium permeability.The distribution area of the basement reservoirs is adjacent to the Jurassic hydrocarbon kitchen to the west of Pingdong area.The natural gas generated in the kitchen migrated along the well-developed deep-rooted large faults and unconformities at the bottom of basement; then got effectively sealed by the gypsiferous mudstones deposited under the Paleogene saline lacustrine environment on the basement top; and ultimately got accumulated in the faulted anticline trap formed during the Late Pleistocene, resulting in the formation of weathering crust gas reservoir on the basement top.In all, the research results are of instructional significance to further exploration of basement gas reservoirs in Jianbei slope, Qaidam Basin.

    Diagenesis and physical properties of subsalt dolomite reservoirs of the Cambrian, Bachu-Tazhong areas, Tarim Basin
    Lijuan Cheng, Zhong Li, Jiaqing Liu, Jingbo Yu
    2020, 41(2):  316-327.  doi:10.11743/ogg20200208
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    The effective subsalt dolomite reservoirs in the Tarim Basin are characterized by great spatial heterogeneity.The reservoir distribution therein is under the influence of both high-energy sedimentary facies belts such as grain shoal and organic reef facies, and diagenetic modification.To further understand the restriction mechanism of diagenetic modification on dolomite reservoirs, we thoroughly described the subsalt dolomite characteristics through microscopic observation, geochemical analysis and logging data interpretation of drilling core samples taken from Bachu-Tazhong areas.The results indicate that the Lower Cambrian subsalt dolomites are dominated by micrite dolomite, grain dolomite, microorganism dolomite and fine-crystalline dolomite.The reservoirs mainly evolved from early-stage diagenetic modification by meteoric water, middle-stage porosity preservation, to continuous improvement of reservoir properties at later stages.The high-quality subsalt dolomite reservoirs are the combined products of proper dolomitization, shielding effect of the overlying gypsolytes on the underlying intervals, and dissolution by thermal fluids in the later periods.Vertically, there are five diagenetic zones in the reservoir under tectonic-hydrothermal modification:hydrothermal mineral developing zone, hydrothermal brecciation zone, fracture developing zone, dissolution zone, and hydrothermal dolomite zone of cementation.Among them, the dissolution zone is the most significant contributor to reservoir improvement, followed by the fracture developing zone.

    Hydrochemical characteristics of formation water and its relationship with hydrocarbon migration and accumulation in Fuyang oil layer in Fuxin Uplift, Songliao Basin
    Xiaohan Mei, Qin Zhang, Yayun Wang, Xinsong Wu, Jingyan Liu, Jiahong Zhao, Wuxue Wang
    2020, 41(2):  328-338, 358.  doi:10.11743/ogg20200209
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    After nearly 60 years of exploration and development, Fuyang oil layer in Fuxin Uplift still remains one of the most important hydrocarbon accumulation zones in Southern Songliao Basin.However, the structural setting of Fuxin Uplift is complex:faults are densely developed, the contacts between oil, gas and water layers are extremely complex, and the process of hydrocarbon migration and accumulation and the hydrocarbon enrichment pattern stay to be identified.These factors greatly restrict further efforts made for hydrocarbon exploration and development.Following the analysis of the origin and the vertical and horizontal distribution patterns of formation water in Fuyang oil layer on the northern slope of Fuxin Uplift, we dissected the typical reservoir profiles in key areas, and made an in-depth discussion on the coupling relations between formation water characteristics and hydrocarbon migration, accumulation and enrichment in Fuyang oil layer in Fuxin Uplift in combination with analysis of formation pressure and source rocks.Vertically, five hydrochemical zones can be identified in Fuxin Uplift:diluted zones from meteoric water percolation, diluted zone from compaction, concentrated zone from dissolution, diluted zone from clay mineral dehydration, as well as concentrated zone from over flow.In the plane, the Xinbei and Xinli nose-like structural zones in the study area are the areas where two major centrifugal flows converge and result in cross-formational flow, leading to the high consistency between zones of high salinity and high sodium chloride coefficient and zones of hydrocarbon enrichment.The oil source conditions are relatively better in the intra-source and near-source hydrocarbon accumulation zones, and the depth of hydrocarbon-bearing fluid disturbance is deeper, favorable for hydrocarbon accumulation.However, the source rocks in out-of-source hydrocarbon accumulation zones are low in maturity, and the depth of hydrocarbon-bearing fluid disturbance is shallow, unfavorable for hydrocarbon accumulation.

    Organic geochemistry identification of high-quality source rocks in the 2nd member of Liushagang Fm and its controls on petroleum occurrence in the Weixi'nan Sag, Beibuwan Basin
    Gang Gao, Xinde Xu, Shiju Liu, Jun Gan, Chenhui Hu, Jianyu Zhao
    2020, 41(2):  339-347.  doi:10.11743/ogg20200210
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    In the Weixi'nan Sag of the Beibuwan Basin, the high-quality lacustrine source rock in the Liushagang Fm has been poorly understood in terms of its characteristics and its controls on hydrocarbon distribution.To this end, we establish an organic geochemical method to identify quality source rocks, and reveal the source rock distribution pattern and its controls on hydrocarbon distribution, based on the fundamental mechanisms of hydrocarbon generation and expulsion for source rocks.Among others, the major source rocks for the Weixi'nan Sag are the Liushagang Fm shale, which can be divided into three intervals, namely the Liu 3, Liu 2 and Liu 1 members downwardly, with the Liu 2 member as the major zone.Based on the principle of hydrocarbon generation and expulsion for source rocks as well as relations between the TOC content, and the pyrolysis S1 and chloroform bitumen "A" content of mature source rocks, we identify the lower limit value of TOC content of the high-quality lacustrine source rocks in the Liushagang Fm is about 2%.The black shale at the bottom of the Liu 2 member (El2) with a TOC content higher than 2%, contains oil-prone organic matters with high hydrocarbon-generating potential, and is high-quality source rocks.Part of the dark mudstone is also high-quality source rocks.The crude oil expelled from the black shale at the bottom of Liu 2 member could migrate in short distance and accumulate under the black shale interval, or could migrate laterally in long distance along the sand bodies in the Liu 3 member and accumulate at higher structures.However, the crude oil expelled from the dark mudstone mainly accumulates in the Liu 1 member and Weizhou Fm, which are vertically above the quality source rocks inside the sag, with faults as the vertical pathway for migration and thus the accumulation is directly characterized by source rock distribution.

    Organic geochemical characteristics of the Carboniferous-Jurassic potential source rocks for natural gas hydrates in the Muli Depression, Southern Qilian Basin
    Dongwen Fan, Zhenquan Lu, Guangzhi Li, Rui Xiao
    2020, 41(2):  348-358.  doi:10.11743/ogg20200211
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    During the investigation of the basic geological profile of natural gas hydrates in the Muli Depression, Southern Qilian Basin, we analyzed the carbon-rich mudstone and mudstone sampled from 5 sections of the Carboniferous, Per-mian, Triassic and Jurassic sequences.The geochemical characteristics such as organic matter abundance, organic matter type and organic matter maturity of four sequences were accordingly studied in detail.The organic geochemical indexes of each sequence were analyzed and compared in order to explore the gas source rock qualities for different sequences of (gas) source rocks for natural gas hydrates.The results show that the Carboniferous-Permian organic matter abundance is relatively low, the TOC (total organic carbon) content is generally less than 0.4%, both of which indicate the source rocks are very lean.The kerogen are mainly over-matured TypesⅡ and Ⅲ organic matters, resulting in poor hydrocarbon generation capacity.Thus, the source rocks could not be the potential gas source rocks for natural gas hydrate generation.The samples collected from the Triassic strata have TOC value of generally greater than 1% and an average chloroform bitumen "A" of 0.89, which are mostly good and very good source rock samples, with a small number of samples with poor or non-hydrocarbon source rock quality.The organic materials are mainly matured Type Ⅲ as a whole with a small number of Type Ⅱ2, with a vitrinite reflectance (Ro) value of 0.74%-0.98%.These strata can be viewed as the main potential gas source rocks for natural gas hydrate generation.The Jurassic strata are dominated by source rocks of very good, good, and medium qualities with limited number of poor source rocks.Their organic materials are mainly matured Type Ⅱ and Ⅲ with a Ro value of 0.62%-0.97%, and thus can be regarded as the secondary potential gas source rocks for the generation of natural gas hydrates.

    Simulation of hydrocarbon generation and expulsion for the dark mudstone with Type-Ⅲ kerogen in the Pinghu Formation of Xihu Sag in East China Sea Shelf Basin
    Chenjie Xu, Jiaren Ye, Jinshui Liu, Qiang Cao, Yiyong Sheng, Hanwen Yu
    2020, 41(2):  359-366.  doi:10.11743/ogg20200212
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    In order to finely describe the hydrocarbon generation and expulsion process of source rocks and provide reasonable key parameters for quantitative evaluation of oil and gas resources, we carried out a simulation research under semi-open system on hydrocarbon generation and expulsion for the dark mudstone with Type-Ⅲ kerogen in the Eocene Pinghu Formation in the Xihu Sag, East China Sea Shelf Basin.The results show that the process of hydrocarbon generation and expulsion can be divided into five stages as follows, 1) Ro=0.5%-0.7%, when oil was generated slowly without expulsion; 2) Ro=0.7%-1.0%, when oil was generated and expelled rapidly; 3) Ro=1.0%-1.5%, when oil began to be cracked into hydrocarbon gas; 4) Ro=1.5%-2.3%, when gas generation predominated; and 5) Ro>2.3%, when only dry gas was generated.Oil expulsion threshold (Ro) of the source rock of this type is about 0.7% (Ro=0.7%), having a wide gas-window of Ro=1.0%-3.0%.So it can maintain relatively strong gas generation ability at high-and over-mature stages, belonging to gas-prone source rock.Following the study on experimental results and the characteristics of hydrocarbon generation and expulsion in samples, we established a set of mathematical models for the evaluation of the process and potential of gas generation and oil generation and expulsion of the dark mudstone with Type-Ⅲ kerogen in the study area.Compared with the thermal simulation experiment in a closed system, the cumulative yield of oil in the semi-open system is higher and closer to that under actual geological conditions.Accordingly, we may conclude that more oil and gas resources may exist in the Xihu Sag.

    Characteristics and controlling factors of organic pores in the 7th member of Yanchang Formation shale in the Southeastern Ordos Basin
    Zhenjia Cai, Yuhong Lei, Xiaorong Luo, Xiangzeng Wang, Ming Cheng, Lixia Zhang, Chengfu Jiang, Qianping Zhao, Jintao Yin, Likuan Zhang
    2020, 41(2):  367-379.  doi:10.11743/ogg20200213
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    Recent studies have shown that organic pores are developed in the medium-to-low-maturity shale of the 7th member of Yanchang Formation in the Southeastern Ordos Basin, but the influencing factors on the development of organic pores in the continental shale reservoir need to be further understood.With the aid of argon ion polishing and FE-SEM observation, we observed the characteristics of organic pores in Chang 7 shale in the Southeastern Ordos Basin.Statistical analysis was made on the organic pore sizes in kerogen of different maturity and different types of migrated solid organic matters, and also on the ratio of organic pore area to the total organic matter area (SR) of these organic matters.Thereaf-ter, main factors affecting the development of organic pores were discussed.The results indicate that organic pores were widely developed in shales of diverse maturity (Ro:0.5%-1.25%) in the Chang 7 member, but there were significant differences in the development of organic pores in kerogens and migrated solid organic matters.Sedimentary organic matter (kerogen) occurs mainly in the form of enrichment along beddings, isolated dispersion and combination with clay minerals in shale and has relatively lower degree of organic pore development.The ratio of the organic pore area to the total organic matter area ranges from 0% to 44.13%, averaging at 6.03%, but generally less than 10%.The majority of organic pores ranges from 10 nm to 40 nm in size.The migrated solid organic matters mainly occurs in inorganic mineral pores, including inter-particle pores/inter-particle dissolution pores in rigid particles, inter-particle pores/inter-particle dissolution pores between rigid particles and clay minerals, intercrystalline pores in pyrite of shale.These organic matters have relatively higher degree of organic pore development.The ratio of the organic pore area to the organic matter area varies from 0% to 46.51%, averaging at 23.05% and generally less than 30%.In addition, the pore size is larger, mainly ranging from 50 nm to 100 nm.The development of organic pores in the Chang 7 member shale is mainly controlled by the organic matter type, the abundance of migrated solid organic matters and the maturity of organic matter:positively correlated with higher content of migrated solid organic matters and more maturity of the organic matters.

    Pore classification and thin section porosity quantification of reservoir in the T2l4(3) in Majing area, Western Sichuan Basin
    Zhemin Hao, Guoming Xu, Hongde Chen, Qiongxian Wang, Ke Long, Wenkai Wang, Qiang Wang
    2020, 41(2):  380-392, 422.  doi:10.11743/ogg20200214
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    Quantitative analysis of the characteristics and porosity of the reservoir in the third interval of the 4th member of Middle Triassic Leikoupo Formation (T2l4-3) in Majing area, Western Sichuan Basin, was carried out through thin section observation, physical property analysis, and thin section porosity quantification of the reservoirs in Well A1.The results show that the reservoirs are mainly developed in dolomitic flat, algal dolomitic flat and lime-algal dolomitic flat, with intercrystalline pores, intercrystalline dissolved pores and fractures as the dominant pore types, and intergranular (dissolved) pores, intragranular (dissolved) pores, moldic pores, framework pores, fenestral pores and dissolved fractures as the minor pore types.In addition, the main rock types were identified therein as crystalline dolomite, crystalline granular dolomite, granular crystalline dolomite, and lime dolomite.Among others, dolomitic limestone of crystalline granular type dominates in the reservoir of the upper section of T2l4-3, while grained crystalline dolomite and crystalline granular dolomite dominate in the reservoir of the lower section of T2l4-3 in Majing area.The quantified thin section porosity is well correlated with the tested porosity for different types of rock.What's more, the quantitative analysis can be applied to calculate the thin section porosity of different sedimentary microfacies, rock types and reservoir spaces.It can serve as a supportive method for the fine study of carbonate reservoir characteristics.

    Differential gas accumulation process of the Middle Permian Qixia Formation, Northwestern Sichuan Basin
    Bing Luo, Long Wen, Ya Zhang, Chen Xie, Jian Cao, Di Xiao, Guohui Gao, Xiucheng Tan
    2020, 41(2):  393-406.  doi:10.11743/ogg20200215
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    A great breakthrough has been made lately for natural gas exploration of the Middle Permian Qixia Formation, Northwestern Sichuan Basin, revealing a typical and unique case of differential hydrocarbon accumulation among different structural zones of the fold-thrust belt-basin system.Based on the analysis of geochemical characteristics of inclusions and geological conditions, we conducted the investigation of differential accumulation process, being of referential meaning to areas of similar geological setting, and of instructional significance to further exploration deployment in the study area.The results show that the Qixia Formation reservoirs in the fold-thrust belt represented by Kuangshanliang and Hewanchang areas are filled with plenty of bitumens and the quartz cements precipitated from acidic fluid following two-stage hydrocarbon charging and one-stage damage, leading to poor gas storage potential.In contrast, the reservoirs in the frontal zone of fold-thrust belt typically shown by Shuangyushi area and in the forebulge zone represented by Jiulongshan area, are filled with limited bitumen and quartz, but massive calcite cements precipitated from alkaline fluids.The former underwent two stages of hydrocarbon charging and one stage of hydrocarbon adjustment, while the latter only went through one-stage hydrocarbon charging, resulting in relatively good gas storage potential.Stable preservation is a critical factor controlling large gas accumulation formation.The underdevelopment of deeply-rooted large faults resulted in limited hydrocarbon charging from the deep Lower Cambrian source rocks under the impact of week compression stress in the frontal zone of fold-thrust belt and forebulge zone.However, the Middle Permian source rocks of sapropelic-humic types are favorable for the formation of self-sourced indigenous play.The stable tectonic setting is conducive to reservoir preservation.In all, the deep-ultra deep hydrocarbon exploration in sags of basin-mountain junction belts is worthy of more attention.

    Characteristic analysis of seismic response of micro-fractures in organic-rich shale: A case study of Well Ning201 in the Changning demonstration zone
    Bole Gao, Renfang Pan, Jineng Jin, Jian Zhang, Shengxian Zhao, Jie Yan
    2020, 41(2):  407-415.  doi:10.11743/ogg20200216
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    In order to make it clear how the density and strike of structural micro-fractures affect the seismic response features of organic-rich shale in Longmaxi-Wufeng Formations distributed in Changning demonstration zone, Sichuan Basin, we carried out the AVAZ forward modelling based on the geologic model built by the coring data obtained from the dril-ling of organic-rich shale in Well Ning201 and the reflection coefficients calculated by HTI anisotropy media.Meanwhile, the seismic response characteristics of the micro-fractures in organic-rich shales from the well were analyzed combined with the contrast and verification of seismic exploration data in the research area.The results show that:on the one hand, the seismic identification of micro-fractures in organic-rich shale is controlled by incident angle, azimuth and dominant frequency of the seismic data.The incident angles determine the amplitude difference caused by micro-fracture densities, the azimuth affects the identification of micro-fracture strikes, while the dominant frequency ensures that the tuning effect of seismic waves makes no difference to amplitude.On the other hand, the amplitude decreases as the included angle between propagation direction of the seismic wave and the normal direction of the fracture surface increases, and reaches the minimum when the included angle is 90°.The amplitude of azimuth parallel to the micro-fracture strike shall not be affected by the variation of micro-fracture density, while the amplitude of azimuth perpendicular to the fracture surface increases with the increase of micro-fracture density.Overall, the research results may serve as a basis for seismic interpretation later of micro-fractures in the organic-rich shale of Changning demonstration area.

    Characteristics and hydrocarbon accumulation pattern of heavy oil reservoir of fracture-pore limestone in EBANO oilfield, Mexico
    Xixian Wang
    2020, 41(2):  416-422.  doi:10.11743/ogg20200217
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    The geology feature of EBANO oilfield in Mexico is complex, leading to difficulty in predicting hydrocarbon distribution, and poor development results.Based on the core description, well logging and seismic data, and well production performance data, we studied the reservoir characteristics and the main factors controlling hydrocarbon accumulation in a systematic way.The results show that the limestone KSF and Kan strata of the Upper Cretaceous are the major pay zones of EBANO oilfield.Due to regional tectonic movement, the fault system shows large difference between the northern and southern parts, with of smaller rank in the north:shorter fault displacement, fewer horizons getting incised and shorter extension distance in the north, and larger rank ones to the south.The reservoir space is dominated by both matrix pores and fractures:the oil-bearing matrix is strong in heterogeneity, and the oil content surrounding faults is high.The hydrocarbon enrichment in EBANO oilfield is controlled mainly by fault, structure, fracture and effective thickness of matrix.Given the above-mentioned new understandings, we implemented a strategic transfer of well emplacement from the higher structures in the north to the lower structures in the south.The development results is obviously improved with the average initial production of new wells 2.1 times that of the old ones, laying a foundation for the successful development of the oilfield.

    Geochemical characteristics of the Mesozoic source rocks and the remaining resources in the Western Desert Basin, Egypt
    Xiaolan Yang
    2020, 41(2):  423-433.  doi:10.11743/ogg20200218
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    The West Desert Basin is one of the three major hydrocarbon-bearing areas in Egypt, with a large number of oil and gas fields discovered therein.At the middle stage of exploration and discovery now, the risk of preliminary prospecting increases.The study focuses on the quantitative analysis of remaining resource potential by basin numerical simulation technology following the detailed evaluation of geochemical characteristics of the source rocks.The results show that the dark shale of coal measures in the Safa and Zahra members of the Middle Jurassic Khatatba Fm and that of the AR-F member in the Upper Cretaceous Abu Roash Fm are the three sets of major source rocks in the basin; and the source rocks are widely distributed in each depression with the thickness varying greatly.The source rocks in the Khatatba Fm have a TOC content ranging from 0.5% to 10% and a high content of cracked hydrocarbon S2, thus are fair-to-very good source rocks.While the AR-F source rocks in the Abu Roash Fm have a TOC content varying between 0.5% and 3% and a moderate-to-high content of cracked hydrocarbon S2, thus belong to fair-to-good source rocks.The kerogen of these source rocks is dominated by mixed Type II, followed by Type III and minor Type I.It is pointed out that the two sets of source rocks in the Khatatba Fm within the whole basin are at the thermal evolution stage of hydrocarbon generation and expulsion in a large amount; that in the center of the depression reaches high mature stage and even over mature stage locally, with oil and gas co-generated.As for the AR-F section of the Abu Roash Fm, only the source rocks in Abu Gharadig and Natrun Sags enter the mature stage of hydrocarbon generation.It is suggested that the hydrocarbons in the northern part of the basin are mainly contributed by the source rocks of the Jurassic Khatatba Fm, while those in the southeastern part are supplied by source rocks in both the Jurassic Khatatba Fm and the Cretaceous AR-F section.The calculation shows that the remaining volume of recoverable resources in the basin reaches up to 6.51 x 108t, indicating huge resource potential.The Paleozoic, Jurassic and Lower Cretaceous AEB in the Abu Gharadig Sag in the south, and the Paleozoic in the Matruh Sag and the Upper Cretaceous in the Faghur Sag in the north, are low in exploration maturity and high in remaining resource potential, thus being favorable targets for future exploration.

    Methods and Technologies
    Key technologies for EOR in fractured-vuggy carbonate reservoirs
    Zhijiang Kang, Yang Li, Bingyu Ji, Yun Zhang
    2020, 41(2):  434-441.  doi:10.11743/ogg20200219
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    China is rich in fractured-vuggy carbonate oil reserves, with proved reserves in place of 29.3×108 t, which has become an important target for China's hydrocarbon exploration and development, and important contributor for the increase of reserves and production.Due to the low reservoir and fluid description accuracy, the variation in flow patterns, and the difficulty to predict flow pattern by simulation of carbonate fractured-vuggy reservoirs in a burial depth of 6500m, the transverse flow in water injection is prone to cause abrupt watered-out wells, resulting in a low recovery rate of only 14.9%.Development and production in such reservoirs are a world-class problem.After many years of research and practice, we developed a series of technologies to enhance oil recovery, including geophysical description, geological modeling, water and gas injection, and acid fracturing.The developed STOOIP has increased 42% with an EOR(enhanced oil recovery) of 2.3 percent in the structural units tested with the new technologies, which are applicable to the development of similar deep or ultra-deep reservoirs with strong heterogeneity.

    Prediction for the formation water salinity in low-permeability reservoirs with complex wettability: A case study of the Triassic Chang 81 member, Longdong area, Ordos Basin
    Cheng Feng, Haitao Fan, Yujiang Shi, Xuekun Chen, Gaoren Li, Zhiqiang Mao
    2020, 41(2):  442-448.  doi:10.11743/ogg20200220
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    The testing data indicate that formation water salinity of low-permeability reservoirs varies in a wide range.What's worse, under the impact of complex wettability, classical methods including spontaneous potential and a combination of reservoir resistivity and porosity fail to predict formation water salinity.This leads to great difficulty in the prediction of reservoir oil saturation.To this end, we proposed a new method to predict the formation water salinity with the results verified by experiments.The new method is shown as follows:assuming the salinity of formation water was approximately equal to that of irreducible water in adjacent mudstones, we carried out resistivity and acoustic logging in the relatively stable parts with high natural gamma ray, without borehole enlargement and low resistivity in adjacent mudstones; then conducted compaction correction of the interval transit time; and at last identified the mudstones of diverse salinity (0-20 g/L, 20-40 g/L, 40-60 g/L and >60 g/L) via cross-plotting the resistivity vs.corrected interval transit time.In practice, a contour map of formation water salinity of the study area was drawn by using the formation water salinity of Chang 81 member in 106 wells predicted by this method and in combination with the test results of 69 formation water samples.This is conducive to the selection of formation water salinity and the planar distribution pattern study of salinity.In addition, the newly proposed method in the study serves as a feasible method for the prediction of formation water salinity in low-permeability reservoirs with complex wettability, and is universally applicable.