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2020 Vol. 42, No. 2

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2020, 42(2): .
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Tectonic-sedimentary characteristics and exploration plays in the western section of Deyang-Wusheng Intracratonic Sag, Sichuan Basin
LUO Kaiping, CAO Qinggu, PENG Jinning, LI Longlong, ZENG Huasheng, ZHANG Hong
2020, 42(2): 163-171. doi: 10.11781/sysydz202002163
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The tectonic-sedimentary characteristics and exploration plays in the western section of the Deyang-Wusheng Intracratonic Sag in the Sichuan Basin were studied by combining geophysical and surface geological data and exploration results. The Deyang-Wusheng Intracratonic Sag is a northwest trending tectonic unit formed in the Changxing period of the Late Paleozoic under a weak extension stress background. It has a trough-like structure, and is thick on both sides and thin in the middle. High energy facies such as biological reefs and bioclastic beaches are developed at the edges (platform margins) on both sides, which is conducive to reservoir development. Lithological combinations of microcrystalline limestone, siliceous mudstone, carbonaceous mudstone and shale developed under deep water in the center of the trough are favorable source rocks. A strip-shaped biological reef developed along the northwest platform margin in the Longbaoliang 3D work zone in the western section of the Deyang-Wusheng Intracratonic Sag. Combined with underlying source rocks such as the Longtan Formation, it forms "lower source and upper reservoir" and "side by side" source-reservoir combinations. The marginal facies of the intracratonic sag is a potential exploration area, and the Longbaoliang area is a favorable target for exploration.
Evidence of two-stage strike-slip structural deformation of Shaya Uplift, northern Tarim Basin
HE Guangyu, GU Yi, ZHAO Yongqiang, YAO Zewei, ZHENG Xiaoli, XIAO Sidong, HUANG Jiwen, JIA Cunshan, ZHOU Yushuang
2020, 42(2): 172-176. doi: 10.11781/sysydz202002172
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The Shaya Uplift, an important structural belt in the northern Tarim Basin, northwestern China, has been regarded as a thrust belt. However, this recognition is not only incompatible with the flower structures on the seismic profiles, but also contradictory with the fault distribution in a broom or trailer mode in plan view. High-resolution 3D seismic profiles indicate that a two-stage strike-slip structural deformation happened in the Shaya Uplift. The first is from the Late Caledonian to the Indosinian, in which transpressional deformation occurred and a huge positive flower structure was thus formed in the deeper part, and strata were eroded because of the structural uplifting. The second is during the Himalayan, in which a negative inverted/transtensional deformation occurred and a negative flower structure was formed in the shallower part. These results indicate that it is not a uniform tectonic-sedimentary environment in the northern Tarim because of the Shaya Uplift barrier and that the Late Caledonian and the Early Himalayan may be two important structural transformation periods.
Volcanic activity stages and distribution during the Permian in the Shunbei area, Tarim Basin
XIAO Chongyang, YANG Lin, LIN Bo, YOU Donghua
2020, 42(2): 177-185. doi: 10.11781/sysydz202002177
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The Shunbei area, located in the Shuntuoguole Low Uplift in the central Tarim Basin, is covered by superimposed basalt and dacite, where volcanic activity stages in the Permian and areal distribution are more difficult to identify compared with those in the Tahe and Tazhong areas. Through core observations and sampling of Permian volcanic rocks from 27 wells in the Shunbei area, we carried out thin section identifications and geochemical element analyses. Five basic rock types were observed, including basalts, andesites, dacites, tuffs and volcanic breccias. In addition, the volcanic activity was subdivided into 5 eruption cycles (or periods) based on the lithology, the petrophysical log characteristics and the seismic characteristics of the Permian section. The first stage was an eruption of intermediate-acid pyroclastic rocks, with the eruption center located in the Shunbei 3D block. The second stage was an eruption of basic volcanic rocks, which was mainly controlled by paleotopo-graphy. The third and fourth stages featured cone-shaped and shield-shaped intermediate-acid volcanic lava, with stable volcanic sediments between the two stages. The fifth stage was an eruption of basic volcanic lava, which mainly distributed in the east of the study area.
Tectonic evolution and differential deformation controls on oilfield water distribution in western Qaidam Basin
WANG Linlin, YU Dongdong, FU Yun, YAN Min
2020, 42(2): 186-192. doi: 10.11781/sysydz202002186
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The impact of tectonic evolution and differential deformation on the distribution of oilfield water was discussed based on the analysis of tectonic kinematics and geometric characteristics of the western Qaidam Basin combined with the accumulation types and salinity distribution characteristics of oilfield water of the Neogene-Paleogene. The characteristics of differential structural deformation in the western Qaidam Basin are obvious. Controlled by the NW-SE oriented faults, the Yingxiongling Structural Belt features stratified deformation. The hydrochemical types, reservoir types, and salinity of oilfield water of the Neogene-Paleogene are controlled by differential tectonic deformation and multi-phase tectonic evolution. The early Himalayan Movement resulted in water storage structures and deep faults, which provided conditions for the convergence of oilfield water. The late Himalayan Movement promoted the further formation of reservoir space and the adjustment of oilfield water to high structures. The Yingxiongling and northwestern Qaidam structural belts where tectonic fractures develop in saline lacustrine sediments are the favorable areas for salinity enrichment, and the existence of gypsum-salt rock controls the vertical differential distribution of deep brine in the Yingxiongling Structural Belt.
Microscopic reservoir characteristics of different lithofacies from inter-salt shale oil reservoir in Qianjiang Sag, Jianghan Basin: a case study of Paleogene Eq34-10 rhythm
XU Ershe, TAO Guoliang, LI Zhiming, WU Shiqiang, ZHANG Wentao, RAO Dan
2020, 42(2): 193-201. doi: 10.11781/sysydz202002193
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The mineral composition, lithofacies association, pore-fracture type, pore structure and pore development control of the Qianjiang Formation shale oil reservoir in the Qianjiang Sag of the Jianghan Basin were studied using thin section petrography, scanning electron microscopy, mercury injection-liquid nitrogen adsorption and 3D reconstruction of micro-CT. The main lithofacies of Eq34-10 rhythm (the tenth rhythm in the fourth submember of the third member of the Qiangjiang Formation) are laminated argillaceous dolomite, laminated dolomitic (calcareous) mudstone and mirabilite filled laminated dolomitic mudstone. The main reservoir porosity includes interlayer fractures, intergranular pores and intergranular solution pores. The pore development of inter-salt shale oil reservoir is mainly controlled by lithology and lithofacies, and the pore development degree of mirabilite filled laminated dolomitic mudstone, laminated dolomitic (calcareous) mudstone and laminated[JP3]argillaceous dolomite increase accordingly. Macro-pores are the most developed porosity in the laminated argillaceous dolomite facies, with the best pore connectivity and oil-bearing properties, and is the dominant lithofacies in the inter-salt shale oil reservoir and the most favorable exploration target.
Sedimentary environment, hydrocarbon potential and development of black rocks in upper Maokou Formation, northwestern Sichuan
HU Chaowei, HU Guang, ZHANG Xihua, CHEN Cong, PENG Hanlin, Gao Zhaolong, LIAO Zhiwei, PANG Qian, YOU Jie
2020, 42(2): 202-214. doi: 10.11781/sysydz202002202
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A set of organic-rich black rocks (23.8 m), mainly consisting of siliceous rocks, shale and limestones, outcrops between carbonate rocks of the Maokou and Wujiaping formations in the Xibeixiang section, northwestern Sichuan Basin, at the margin of the Upper Yangtze Platform. Detailed conodont stratigraphy, organic petrology and organic geochemistry studies were performed on samples from the Xibeixiang section. The conodonts found in the study area were Jinogondolella prexuanhanensis, J. xuanhanensis and Clarkina posbitteri hongshuiensis. All of them lived at the end of Guadalupian, confirming that the black rocks in the section were deposited during the late period of the Maokou Formation indicating that the Guangyuan-Wangchang Marine Trough began to develop in the late Guadalupian stage on the Upper Yangtze Platform. The detailed study of organic petrology reveals that benthic algae is the main contributor for hydrocarbon in the black rock series, with a small amount of macroplanktonic algae, and the organic matter is type Ⅱ. The organic geochemical analyses of the black rocks show that the TOC content ranges 1.04% to 32.58% and the chloroform bitumen "A" content ranges 0.03% to 1.05%, indicating favorable source rocks. Thermal parameters, such as the vitrinite reflectance (Ro) value ranges 1.0% to 1.4%, the Tmax value ranges 440 to 460℃, the conodont color index (CAI) ranges 1.5 to 2.5, the Ts/Tm ratio ranges 0.35 to 1.43, the moretane/hopane ratio ranges 0.05 to 0.39, the C2920S/(20S+20R) ranges 0.39 to 0.65, and the C29αββ/(αββ+ααα) ranges 0.26 to 0.58, which indicate that these black rocks are mature to highly mature. The integrated study of lithology, hydrocarbon-forming organisms, conodonts and biomarkers indicate that these black rocks were deposited in a relatively reductive deep-water environment with a high salinity.
Restoration of Neogene paleo-geomorphology of Yinggehai Basin
XIAO Kunze, TONG Hengmao, YANG Donghui, LI Xusheng, FAN Caiwei, ZHANG Hongxiang, HUANG Lei
2020, 42(2): 215-222. doi: 10.11781/sysydz202002215
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The Neogene Sanya and Meishan formations are important sequences of source rocks in the Yinggehai Basin. Understanding the paleo-tectonic geomorphology is an important basis for predicting the distribution of source rocks and the potential of oil and gas resources. Based on the rule that "the paleo-tectonic environment develops in the inherited way when tectonic stress system remains unchanged", we applied the idea and method of "the present is the key to the past" and "proportional compensation" to interpret the Neogene tectonic deformation system and its evolution in the Yinggehai Basin. The current geomorphological features and stratigraphic thickness distribution were used with the paleo-sea depth determined from single well data as a constraint to restore the Neogene paleo-geomorphology of the Yinggehai Basin. The Yinggehai Basin was a semi-enclosed confined bay during the deposition of the Sanya and Meishan formations, which was conducive to the development of source rocks. The "proportional compensation" method, which is a new way for paleo-geomorphology restoration, can be applied in other basins.
Reservoir characteristics of high clay content and microporous tight litharenites in marine-continental transitional environments
LIU Zengqin, GUO Shaobin
2020, 42(2): 223-232. doi: 10.11781/sysydz202002223
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The resource potentials for the exploration and development of tight sandstone gas, shale gas, and coalbed gas in marine-continental transitional environments are very attractive. However, previous studies have mostly focused on the geological and geochemical characteristics of marine-continental transitional shales and coals, and less attention has been paid to the associated tight sandstones. This paper takes the sandstones in the west Guizhou as an example. The Longtan marine-continental transitional tight sandstones have been investigated using various techniques (e.g., thin section, mercury injection capillary pressure, and nuclear magnetic resonance) to illustrate the reservoir characteristics. The Longtan sandstones, according to our study, are classified as litharenites, and are characterized by thin layers, high rock fragment and clay contents, abundant micropores, complex pore-throat structures, and low porosities and permeabilities. Compared with other typical tight sandstones in China, the Longtan sandstones have more lithic content and tighter pore throat structures. Therefore, tight-gas potential is interpreted to be limited in the Longtan sandstones. However, a model for the commingled production of tight-sand gas, shale gas and coalbed methane could be viable since the Longtan sandstones are interbedded with coals and shales, which provides an opportunity for unconventional gas development in marine-continental transitional environments.
Tectonic controls on the pre-salt hydrocarbon distribution in block A of Campos Basin, Brazil
ZHAO Wenfang
2020, 42(2): 233-240. doi: 10.11781/sysydz202002233
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Block A in the southern Campos Basin in the deep water of Brazil has complicated pre-salt structures as a result of the Late Jurassic tectonic activity. Based on new 3D seismic and drilling data, the geological attributes, fault development and tectonic evolution of pre-salt in block A were reviewed. Four seismic reflection layers and three seismic sequences were identified in the pre-salt section. Block A also experienced three stages of tectonic evolution, including rifting, erosion and tilting as well as thermal subsidence. Additionally, NE and NNE normal faults are well developed in this region. Tectonic activity also resulted in a NW-SE transform fault in the region and this controlled the distribution of normal faults. Finally, the influence of tectonic activity on hydrocarbon distribution was discussed and it is expected to provide scientific basis for the pre-salt exploration activities in block A and Campos Basin.
Heat-flow value of Late Mesozoic to Cenozoic in Putumayo Sub-Basin, Republic of Colombia
MENG Qingqiang, SONG Lijun, YUAN Bingqiang
2020, 42(2): 241-247. doi: 10.11781/sysydz202002241
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The heat-flow history of the Putumayo Sub-Basin has undergone a long-term and complex evolutionary process from the Late Mesozoic to the Cenozoic due to multiphases of tectonic evolution. The regional geologic background and the forward modeling of paleo-temperature were applied to determine the heat-flow value during different stages ever since the Cretaceous. The heat-flow value was 64 mW/m2 in the Cretaceous, 95 mW/m2 in the Paleocene, 38 mW/m2 at the end of Oligocene, 120 to 190 mW/m2 (increasing from east to west and averaging 155 mW/m2) in the Pliocene, and 55 mW/m2 at present.
Oil and gas sources in Shunbei Oilfield, Tarim Basin
GU Rong, YUN Lu, ZHU Xiuxiang, ZHU Meng
2020, 42(2): 248-254. doi: 10.11781/sysydz202002248
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The hydrocarbon sources in the Middle and Lower Ordovician in the Shunbei area of the Tarim Basin were studied based on the geochemical characteristics of oil and gas samples. The saturated hydrocarbon gas chromatography, mass spectrometry of crude oil and natural gas, and the carbon isotope distribution of whole oil and group components were used. The C23 tricyclic terpane is dominant in crude oil samples from the Shunbei area, with a low content of gammacerane. The C27-C28-C29ααα20R regular steranes show an irregular "V" shape distribution. The regular steranes account for a larger amount than the rearranged steranes, and the carbon isotope of the crude oils is light. The geochemical characteristics of crude oil samples from the Middle and Lower Ordovician in the Shunbei area have a good affinity with those from the Lower Cambrian in the Keping outcrop and the well KT1. The δ13C1 and δ13C2 values of natural gas samples are -50.7‰ to -44.7‰ and -36.1‰ to -33.1‰, respectively. The gas dryness coefficient ranges from 0.520 to 0.883. The oil and natural gas in the Shunbei Oilfield have the same source, that is, the Lower Cambrian source rocks. The distribution of source rocks in the Lower Cambrian of the Tarim Basin was predicted by means of drilled lithofacies, sedimentary facies and seismic facies of the whole basin. The source rocks are about 30 m thick. They have a high TOC content and show a great hydrocarbon generation potential. They have experienced a long term of hydrocarbon generation and multiple stages of hydrocarbon supply, providing significant oil and gas resources for the Tarim Basin.
Genetic types and sources of Cretaceous crude oil in Shunbei area, Tarim Basin
WU Xian, CAO Zicheng, LU Qinghua, HONG Caijun
2020, 42(2): 255-262. doi: 10.11781/sysydz202002255
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The Cretaceous oil-bearing strata in the Tarim Basin have a good exploration potential. The Shunbei area has good oil and gas shows in the Cretaceous, and a small amount of crude oil has been obtained by testing. The geochemical characteristics of the Cretaceous crude oil as well as the oil-oil and oil-source correlations were studied systematically in order to determine the genesis types and sources of crude oil in the Shunbei area. The saturated hydrocarbon chromatogram of the Cretaceous crude oil in the Shunbei area shows a unimodal distribution. The n-alkanes are intact and the distribution is unchanged without any obvious "UCM". The Pr/Ph values of crude oil range 1.65-1.71. The C21TT/C23TT ratio is >1. In biomarkers, the hopane series are dominant and the ∑tricyclic terpanes/∑hopanes ratio is < 1. The gammacerane and triaryl stanine compounds are abundant, indicating that the crude oil of continental origin is well preserved. The Cretaceous crude oil in the Shunbei area and the Yingmai, Dawanqi and Dalaoba areas around the Kuqa Sag in the north, and the Triassic Huangshanjie mudstones in the Kuqa River area show similar m/z 191 biomarker patterns, which indicates that the crude oil was sourced from the Huangshanjie mudstones in the Kuqa Sag. The thermal evolution degrees of crude oil decrease from Dawanqi, Yingmai to Shunbei. We inferred that the early terrestrial hydrocarbon was sourced in the Triassic source rocks in the Kuqa Sag, and then migrated laterally from north to south through the Cretaceous sand bodies, the T40 unconformity surface and the faults.
Geochemical characteristics of crude oils in the second member of Kongdian Formation shale system, Cangdong Sag, Bohai Bay Basin
LI Wenqi, LIU Xiaoping, GUAN Ming, LIU Huaxin
2020, 42(2): 263-272. doi: 10.11781/sysydz202002263
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Crude oils in the shale system of the second member of Kongdian Formation (Ek2) in the Cangdong Sag of the Bohai Bay Basin were analyzed for physical properties, group composition, quantitative gas chromatography-mass spectrometry of saturated hydrocarbon and aromatic hydrocarbon fractions and stable carbon isotopes. The crude oils belong to medium quality, medium freezing point heavy oil with poor fluidity. The hydrocarbon content in the crude oils is low, and both ratios of saturated hydrocarbon to aromatic and nonhydrocarbon to asphaltene are low. The characteristics of crude oil biomarkers and stable carbon isotope distributions in different structural units are similar, indicating that these crude oils have roughly similar sources and hydrocarbon evolution processes. Almost all the samples have saturated hydrocarbons with a slight dominance of light carbons and are normally distributed with a single peak. The distribution of C27, C28 and C29 regular steranes shows a rising trend, while the tricyclic terpane content is very low, demonstrating that the original organic matter had contributions of lacustrine aquatic organisms and terrigenous higher plants, with the latter being the major contributor. The gammacerane index, the content and distribution of rearranged hopanes, Pr/Ph, dibenzothiophene, dibenzofuran and fluorine series, and stable carbon isotope distribution and other indicators suggest that the crude oil source rocks formed in fresh-brackish and weakly oxidizing to reducing lacustrine environment. The odd/even predominance, the αββ/(ααα+αββ)C29 and 20S/(20S+20R) C29 isomerization index and the hopane isomerization index indicate that the crude oils have low thermal maturity.
Characteristics of source rocks in Shahezi Formation and implications for hydrocarbon accumulation, Changling Fault Depression, southern Songliao Basin
LI Hao, HU Ye, WANG Baohua, LU Jianlin, WANG Miao, LÜ Jianhong
2020, 42(2): 273-280. doi: 10.11781/sysydz202002273
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The paleo-tectonics and sedimentary environment during source rock deposition controlled the macro distribution of source rocks. The deposition environment of the Lower Cretaceous Shahezi Formation (K1sh) source rocks, which are the main source rocks in the Changling Fault Depression of the southern Songliao Basin, was restored based on the theory that "basin prototype controlled source rock development". The distribution of preserved source rocks in the K1sh was determined using tectonic restoration. The paleo-environment of the Changling Fault Depression during the K1sh period was characterized by deep water, humid to subhumid climate and anaerobic freshwater, which was favorable for the deposition of source rocks. The Changling Fault Depression was composed of two relatively unified fault subsags during the K1sh period, and the K1sh source rocks were widely developed. After multiple stages of reversal, the Shahezi Formation was uplifted and eroded to different degrees, and the residual source rocks were mainly found on the present slope. This study provided a new idea for the oil and gas accumulation on the slope belt and the basin margin super-stripping belt. The Longfengshan-Dongling slope, the Chaganhua east slope and the Fulongquan west slope are favorable exploration areas for oil and gas exploration, where excellent source rocks were developed. In addition, the super-stripping zone of the Shahezi Formation is also favorable for hydrocarbon accumulation, showing a certain exploration potential.
Geochemical characteristics and oil-source correlation of crude oils in 6th and 7th members of Yanchang Formation, Fuxian area, Ordos Basin
HUANG Yanjie, GENG Jikun, BAI Yubin, SUN Binghua, HUANG Li
2020, 42(2): 281-288. doi: 10.11781/sysydz202002281
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The geochemical characteristics and oil-source correlation of crude oils in the sixth (Chang 6) and seventh (Chang 7) members of Yanchang Formation in the Fuxian area of the Ordos Basin were studied based on physical properties, group composition, biomarker compounds and oil-source correlation. The Chang 6 and Chang 7 crude oils in the study area are similar in physical properties, both of which are light with a good fluidity. The average mass fraction of saturated hydrocarbons is 71.46%, the average mass fraction of aromatics is 13.27%, and the contents of non-hydrocarbons and asphaltenes are relatively low. The saturated to aromatics ratios of the crude oils are high, averaging 5.43. The n-alkane distribution is dominated by a single peak at C15 and low carbon numbers. The C30 hopane is prominent in biomarker compounds. The regular sterane distribution is anti-"L" type, that is, dominated by C29. Both of the Chang 6 and Chang 7 crude oils are mature. The sedimentary parent material type is lower hydrobiont and contains some terrestrial higher plants, which are deposited in a weakly reduced freshwater-brine water terrestrial sedimentary environment. The oil-source correlation shows that the Chang 6 and Chang 7 crude oils are closely related to the Chang 73 source rocks in this area; however, the relationship with the dark mudstones in the upper part of Chang 7 and the Chang 73 source rocks in the Zhidan area in the basin center is poor. Therefore, it is believed that the crude oil is mainly from the Chang 73 source rocks in this area.
Comprehensive evaluation of Cretaceous source rock maturity in medium and small fault depressions in southern Songliao Basin: a case study of Zhangwu and Changtu fault depressions
WU Yingli, ZHU Jianhui, NI Chunhua, LI Kuang
2020, 42(2): 289-295. doi: 10.11781/sysydz202002289
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A comprehensive evaluation of the maturity of the source rocks in the Cretaceous Shahai and Jiufotang formations in the Zhangwu and Changtu fault depressions of the southern Songliao Basin was made using several indicators, including vitrinite reflectance, hydrocarbon conversion rate, OEP, sterane isomerization and hopanoid distribution. The dynamic evolution process of source rocks with burial depth was described. The hydrocarbon generation threshold is different between the southern and northern fault depressions, resulting in the various maturity stages of source rocks. The hydrocarbon generation threshold of source rocks in the Zhangwu Fault Depression in the south is about 1 000 m. Generally, the source rocks in the Shahai Formation are in the immature and low maturity stages. The source rocks in the upper Jiufotang Formation are in the low maturity stage, while those in the lower part are in the mature stage. The hydrocarbon generation threshold of source rocks in the Changtu Fault Depression in the north is about 1 800 m. Generally, the source rocks in the lower Shahai Formation and the Jiufotang Formation are in the low maturity and mature stages. The middle and lower parts of the Jiufotang Formation in the southern fault depressions developed effective source rocks. The Jiufotang Formation in the northern fault depressions developed effective source rocks, and the middle and lower parts of the Shahai Formation also contributed.
Reserves evaluation for new investment projects in overseas oil and gas field development
WANG Mingchuan, SHANG Xiaofei, DUAN Taizhong, GAO Weiyuan
2020, 42(2): 296-301. doi: 10.11781/sysydz202002296
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Reserve evaluation is the core of asset value evaluation of new investment projects in overseas oil and gas field development and determines the investment income and formulation of a development plan. A method of reserve evaluation was established by using geological modeling in order to reasonably and quickly evaluate the reserves of new investment projects in overseas oil and gas field development, and to provide a basic geological model for the formulation of a development plan. The evaluation consists of data collection, geological framework evaluation, reservoir facies and properties evaluation, and reserve calculation and risk assessment. It can be divided into two stages: geological modeling and reserve evaluation. The geological modeling stage includes three-dimensional modeling of the most probable structures, reservoir facies and properties based on data collection. In the reserve evaluation stage, the uncertainty of the geological framework, reservoir facies and properties are carried out based on the understanding of reservoir uncertainty, then the probabilistic reserve distribution is obtained and the risk of reserve is exposed. Finally, the rapid scientific reserve evaluation of the new investment projects of overseas oil and gas field development is realized. The reserve evaluation method for new investment projects of overseas oil and gas field development based on geological modeling effectively integrates the advantages of volume method and probability method, and the application example shows that the method is practical and can be applied to the reserve evaluation of overseas oil and gas fields.
Analysis and enlightenment of porosity differences between shale plug samples and crushed samples
FU Yonghong, JIANG Yuqiang, CHEN Hu, ZHOU Keming, QIU Xunxi, ZHANG Haijie, LIU Xiongwei, GU Yifan, JIANG Zengzheng
2020, 42(2): 302-310. doi: 10.11781/sysydz202002302
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Shale porosity is one of the important parameters for shale reservoir quality evaluation and shale gas reserve calculation, so it is very important to accurately measure shale porosity. There are many methods to measure shale porosity. Liquid saturation and helium saturation methods are applied to core plugs and crushed samples. At present, there are few comparative studies on the measurement results of the porosity of plug samples and crushed samples, and the differences between them are even less reported. Firstly, the porosity of plug samples is measured using different measurement methods. Then, the plug samples are crushed and the porosity of the crushed samples is measured, and the factors affecting porosity are analyzed. Finally, the differences between the porosity of the plug samples and the crushed samples are compared. The experiment results show that the porosity of shale plug samples (helium saturation method) is the connected porosity of shale, and the porosity of crushed samples is the total porosity of shale, and the latter is 0.65%-2.40% higher than the former, which accounts for 11.21%-44.36% of the total porosity. There are several reasons. (1) The injection pressure of helium saturation method is too low. (2) The samples are not evacuated. (3) A large number of unconnected pores in the shale plug samples are not effectively saturated with helium. The correlation between different mineral components and the porosity of plug and crushed samples shows that the unconnected pores mainly exist in organic matter and a small amount in clay minerals. Appropriate chemical reagents can be added in the process of reservoir transformation to effectively modify the structure of organic matter and clay minerals, and release shale gas in these disconnected pores as far as possible, so as to improve shale gas recovery.
Three-dimensional quantitative fluorescence analysis and application in shale
QIAN Menhui, JIANG Qigui, LI Maowen, LI Zhiming, LIU Peng
2020, 42(2): 311-318. doi: 10.11781/sysydz202002311
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The evaluation of mudstone/shale oil-bearing capacity is the basis for the exploration and development of shale oil. Using three-dimensional quantitative fluorescence analysis, we can quickly evaluate the oil-bearing capacity of mudstone/shale samples. However, the three-dimensional quantitative fluorescence analysis method established for conventional oil and gas cannot be directly applied to mudstone/shale due to the loss of light hydrocarbons and the low porosity and permeability. The comparative experiments of factors such as solvent extraction time, particle size and ultrasound assistance determined the pre-treatment method and analysis process of the three-dimensional quantitative fluorescence analysis of mudstone/shale. A preliminary application was made in the cored section of a shale oil exploratory well in the Jianghan Basin. The 10th rhythm of the Eq34 submember and the 6th and 15th rhythms of the lower Eq4 submember of the Qianjiang Formation show a strong oil-bearing capacity, which are regarded as favorable exploration targets. Compared with rock pyrolysis results, the two methods reflect a consistent change trend of oil-bearing capacity, indicating that the three-dimensional quantitative fluorescence analysis is a fast and reliable method.
Method and application of hydrogen isotope analysis of n-alkanes
QI Yanli
2020, 42(2): 319-324. doi: 10.11781/sysydz202002319
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The source rock and crude oil from the Shahejie Formation in the Dongying Sag of the Bohai Bay Basin were studied. Hydrogen isotopic compositions of n-alkanes from different sedimentary environments were determined using a combination of gas chromatograph, GC/TC interface and an isotope mass spectrometer. In the upper section of the fourth member of Shahejie Formation, the hydrogen isotopic composition of source rocks was heavy, ranging from -161‰ to -111‰. While the hydrogen isotopic composition of source rocks in the lower section of the third member of Shahejie Formation was relatively lighter, ranging from -186‰ to -134‰. The results suggested that from brackish water to saline water sedimentary environment, the hydrogen isotope value shifted toward heavier composition following the increasing of salinity in water. The difference of hydrogen isotopic composition was relatively smaller for samples with large maturity differences. The results indicated that the influence of maturity on hydrogen isotopes of a single hydrocarbon was relatively smaller in the range of the normal oil generation window, which was mainly related to the source of parent material and the sedimentary environment. The characteristics of hydrogen isotopic composition of n-alkanes could provide an important scientific basis for the correlation of oil and source rock and the identification of parent material source and paleosedimentary environment.
2020, 42(2): 325-325.
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