石油实验地质

2018, 40(6): .

Abstract(220) PDF-CN(94)

Abstract:

Rock features and sedimentary environment of the fourth member of Dengying Formation in Hujiaba section of Ningqiang, northern Sichuan Basin

GUO Xusheng, HU Dongfeng, DUAN Jinbao, WU Hao, LI Bisong

2018, 40(6): 749-756. doi: 10.11781/sysydz201806749

Abstract(2048) PDF-CN(417)

Abstract:
In the central Sichuan Basin, significant progress has been made in the exploration of natural gas around the Dengying Formation. However, the exploration in the northern Sichuan Basin is relatively low and the drilling data is scarce. The petrological characteristics of the field geological section and the analysis of the sedimentary environment are of great significance for oil and gas exploration. Based on the survey and systematic sampling analysis of the Dengying Formation, Hujiaba section, sedimentary stratigraphy, rock classification and sedimentary environment analyses were carried out using sedimentology and petrology. Our research showed that:(1) According to the rock types, algae content and shale content, the 4th member of Dengying Formation, Hujiaba section can be divided into upper and lower sub-sections, of which the upper sub-section is the main part of the bioherm-beach and reservoir development; (2) The carbonate rock types of the 4th member of Dengying Formation can be divided into three sub-classes of crystalline dolomite, algae dolomite and granular dolomite, and eight micro-classes; (3) The 4th member of Dengying Formation, Hujiaba section is generally deposited on the edge of the platform, which can be divided into four subfacies of table, interbank sea, algal mound and grain beach. (4) During the deposition period of the fourth member of Dengying Formation, the sea level is characterized by two cycles of transgression and regression. The types of sedimentary rocks are controlled by the sedimentary cycle and sea level which shows a sedimentary evolution process of table facies→interbank sea facies→bioherm-beach facies→interbank sea facies→bioherm-beach facies.

Cement characteristics and effects on dolomite reservoir pores in the fourth member of Leikoupo Formation, Longmen Mountain front, western Sichuan Basin

WANG Qiongxian, SONG Xiaobo, CHEN Hongde, LIU Haonian

2018, 40(6): 757-763. doi: 10.11781/sysydz201806757

Abstract(1126) PDF-CN(163)

Abstract:
Based on the analysis of thin sections, cathode luminescence, electron probe, laser carbon, oxygen isotopes and inclusion thermometry, three periods including five cement types were observed in the dolomite reservoir of the 4th member of the Leikoupo Formation in Longmen Mountain front. Distribution characteristics and development degree indicated a reduction of the influencing process on pore cements. Phase 1 cement is dolomite. Its deposition is the main stage that leads to the porosity decline of the blue green algae agglutinate dolomite. However, after the cementation, the residual porosity has some supporting protection, and a large number of early pores are preserved. Phase 2 cement is the vadose silt that causes reservoir inhomogeneity of the blue green algae agglutinate dolomite. Phase 3 cement is the ferric calcite. These late diagenetic products generally filled in the pores of micritic-silty dolomite to further reduce the reservoir porosity, but this cement was inhibited by the organic acid. Therefore primary pores are well preserved in the long reburial stage.

Paleogeomorphology restoration of Wufeng Formation-Lower Member of Longmaxi Formation in Zigong area of Sichuan Province and its oil and gas significance

WANG Tong, ZHANG Keyin, XIONG Liang, SHI Hongliang, DONG Xiaoxia, WEI Limin, WEN Zhentao, OUYANG Jiasui, LI Bin, WANG Haoyu

2018, 40(6): 764-770. doi: 10.11781/sysydz201806764

Abstract(1171) PDF-CN(244)

Abstract:
The Weiyuan-Zigong area is a main shale gas production area in the Sichuan Basin. The distribution of the Upper Ordovician Guanyinqiao Member provides significant guidance for shale gas exploration. Tectonic-sedimentary background analysis combined with core, thin section, paleontology, logging, deposition rate and carbon-oxygen isotope data were used to interpret the micro-paleogeomorphology of the Zigong area in the Hirnantian-Rhuddanian period. The Guanyinqiao Member comprises shell limestone deposited under the background of regression in the tectonic stabilization period. The Guanyinqiao Member was missing and the Wufeng Formation was thin in wells A205 and A1. The NE-SW-directed Zigong low uplift identified in wells A1 and A205. A sedimentary evolution model of the Zigong area during the Hirnantian-Rhuddanian period was established, and its influence on black shale thickness was clarified. The Wufeng Formation and the high gamma ray value section of Longmaxi Formation thickened around wells A1 and A205. Both sides of the Zigong low uplift are favorable for exploration.

Discovery of metamorphic core complex in Changling Faulted Depression and its controls on hydrocarbons

LU Jianlin, ZUO Zongxin, LI Ruilei, WANG Miao, WANG Baohua, ZHU Jianfeng

2018, 40(6): 771-777. doi: 10.11781/sysydz201806771

Abstract(1223) PDF-CN(125)

Abstract:
Metamorphic core complex was discovered in the Changling Faulted Depression of Songliao Basin. This metamorphic core complex has a typical three-layer configuration, including the metamorphic core, the unmetamorphosed cover and the ductile shear belt. It uplifted during the Yingcheng period in the Early Cretaceous, caused by magmatic emplacement and large-scale extensional detachment. After the orogeny in the Late Jurassic, the orogen extension and collapse and mountain root delamination since the Early Cretaceous resulted in strong crustal thinning and large-scale extensional detachment. At the same time the faulted depression group and metamorphic core complex were formed in the Songliao Basin. The impact of the metamorphic core complex on oil and gas were discussed, suggesting that the metamorphic core complex has an important influence on hydrocarbon accumulation of the Longfengshan Oil-and-Gas Field, which shows good potential for oil and gas exploration.

Reservoir porosity characteristics and controls of the Shanxi Formation shale reservoir, Yanchang area, Ordos Basin

WEN Fenggang, ZHU Yushuang, REN Zhanli, NI Jun, GAO Pengpeng

2018, 40(6): 778-785. doi: 10.11781/sysydz201806778

Abstract(865) PDF-CN(138)

Abstract:
The micro-scale shale reservoir porosity type and the corresponding pore size distribution of the Shanxi Formation in the Yanchang exploration area of the Ordos Basin were analyzed using argon ion polished sections for SEM observation. Helium gas expansion, mercury injection, low pressure nitrogen adsorption, carbon dioxide adsorption, nuclear magnetic resonance (NMR) tests and full pore-size quantitative characterization were applied to study the reservoir physical properties and the pore structure of various rock types. Various geological factors influencing the reservoir pore development and preservation of the Shanxi Formation were discussed from different aspects combined with the mineralogical and geochemical characteristics of reservoir rocks. Results showed that there were differences in pore types, pore sizes and porosity of different rock types of the Shanxi mud shale formation, and there were differences in pore size and development characteristics of different pore types of the same rock type. The organic matter content (asphalt content) of silty shale was decisive for porosity and middle-large pore development. In low TOC shale, quartz feldspar content is a main factor that affects porosity, showing a positive correlation. Organic matter content has a positive influence on the porosity of the high TOC argillaceous shale, while rigid particle size and argillaceous mineral content show a clear negative relationship.

Diagenesis features of Chang 8 tight sandstone reservoir in Honghe Oil Field, Ordos Basin

WANG Mingpei, XIA Dongling, WU Yue, PANG Wen, ZOU Min

2018, 40(6): 786-792. doi: 10.11781/sysydz201806786

Abstract(1325) PDF-CN(109)

Abstract:
The diagenesis types, distribution characteristics and main controlling factors of the tight sandstone reservoir in the 8th member of Triassic Yanchang Formation (Chang 8) in the Honghe Oil Field, Ordos Basin, were systematically studied by using thin sections, scanning electron microscopy and electron probe. The Chang 8 reservoir in the study area is currently in the middle A diagenesis stage. The diagenesis types related to the reservoir quality mainly include compaction, dissolution, calcite cementation, kaolinite cementation and chlorite cementation. The isolated thin layer sand body has a high plastic mineral content and was deposited in the channel flanks and upper reaches of the river. The diagenesis of this sandstone is characterized by strong compaction, weak dissolution and cementation, forming strongly compacted diagenetic facies. The stacked thick sand body was deposited in the center of the river. The top and bottom sand bodies are strongly cemented by calcite, while those in the central part developed multiple diagenetic sequences corresponding to different sandstone lithofacies types. The middle-fine sandstone lithofacies, rich in rigid minerals, includes chlorite cement, and the transitional fine sandstone lithofacies mainly contains kaolinite cement or middle calcite cement.

Identification of effective traps north of Boerjianghaizi Fault, Hangjinqi area, Ordos Basin

QI Rong, LI Liang

2018, 40(6): 793-799. doi: 10.11781/sysydz201806793

Abstract(1364) PDF-CN(99)

Abstract:
The area to north of the Boerjianghaizi Fault is on the northern edge of the tight-gas bearing area in the Upper Paleozoic in the Ordos Basin. A near-source braided river sand body serves as the main reservoir. Sand bodies in this area have low porosity and low permeability, which is nevertheless better than those in the basin. The gas-water differentiation caused by the superposition of a low-permeability channel sand body and a low-amplitude structure complicated trap evaluation and gas-water relationship identification. Through the difference analysis of structure, logging and seismic waveform, a small anticlinal gas reservoir was dissected in Member 1 of Shihezi Formation. The gas-water interface in the trap was made clear and an identification method was proposed. The sand-structural superposition relationship in Member 1 is a wide channel + a small anticline, with small trap area and volume. However, the sand-structural superposition relationship in members 2 and 3 is a narrow channel + a non-closed structure, mostly structural-lithologic composite traps, with a large number of traps and a large trap area. Besides the comprehensive evaluation of sand body, structure, sealing conditions, etc., it is also important to demonstrate the location of the gas-water interface.

Volcanic hydrothermal fluid activity and its influence on carbonate reservoirs in Bohai Sea area

JIN Xiaoyan, DU Xiaofeng, WANG Qingbin, DAI Liming, LIU Xiaojian, HAO Yiwei

2018, 40(6): 800-807. doi: 10.11781/sysydz201806800

Abstract(829) PDF-CN(194)

Abstract:
Volcanic activity is frequent in the Bohai Sea. Hydrothermal fluid activity and its reformation effect on Paleozoic carbonate reservoirs were studied based on core, cast thin section, scanning electron microscopy, carbon and oxygen isotopes, strontium isotope and rare earth elements in combination with fluid inclusion analysis to study the influence of volcanic hydrothermal activity on carbonate reservoirs. The hydrothermal fluid in the Bohai Sea was controlled by fractures. The main ingredients of hydrothermal fluid include a large amount of CO₂ and H₂S gas from the earth mantle. Properties indicating hydrothermal fluid activity included induced joints by hydrothermal fluid, typical rock heat bleaching and typical hydrothermal minerals such as saddle dolomite (first discovered in the Bohai sea area), siliceous nodules, columnar authigenic quartz and veined pyrite. The calcites growing under the influence of hydrothermal fluid are featured by low δ¹⁸O value, high ⁸⁷Sr/⁸⁶Sr, light rare earth enrichment and Eu positive exception, and the homogenization temperatures of salt water inclusions are obviously higher than the formation temperature. When volcanic hydrothermal fluids flowed along faults, a large number of hydrothermally induced fractures were formed in carbonate reservoirs, and hydrothermal dolomitization took place in large intergranular pores. Hydrothermal minerals such as cladding of apatite and siliceous nodules supported and protected the previous apertures. Volcanic hydrothermal fluids flowed along the apertures, forming a large number of dissolution pores in carbonate rocks, which improved carbonate reservoir porosity.

Resource assessment of North Carnarvon Basin on the northwest shelf of Australia

KANG Hongquan, PANG Lin'an, JIA Huaicun, MENG Jinluo, LI Minggang

2018, 40(6): 808-817. doi: 10.11781/sysydz201806808

Abstract(830) PDF-CN(97)

Abstract:
The Carnarvon Basin is one of the major oil and gas enriched basins in the northwest shelf of Australia. The petroleum system and oil and gas distribution characteristics were recognized by analysis of petroleum accumulation elements based on new data and research results. Through the detailed division of assessment units, the resources of each assessment unit were forecasted by a Monte Carlo simulation method. Assessment parameters were determined by multiple methods, such as improved field size sequence and so on. According to the resource assessment of each assessment unit, the resource potential and exploration direction of the North Carnarvon Basin were studied. There are 2 petroleum systems, including the Jurassic Dingo-Jurassic/Cretaceous petroleum system and the Triassic Locker/Mungaroo-Triassic petroleum system. Oil and gas distribution indicated that oil was enriched in grabens and gas was enriched in horsts. Resource evaluation results indicate that the North Carnarvon Basin has great resource potential. The forecasted undiscovered recoverable resources of the basin are 1 560 MMbbl oil, 34 978 Bcf gas and 3 497 MMbbl condensate. Based on comprehensive analysis, the Exmouth Plateau is a favorable exploration area for gas exploration in the future.

Light hydrocarbon characteristics of petroleum in a tight sandstone gas reservoir and its geological significance: a case study of the Upper Triassic Xujiahe Formation gas reservoir in the northwestern Sichuan Basin

WANG Wei, SHEN Zhongmin, PEI Senqi, DAI Hongming, HUANG Dong

2018, 40(6): 818-827. doi: 10.11781/sysydz201806818

Abstract(1115) PDF-CN(119)

Abstract:
Light hydrocarbons (C₇ and C₅-C₇) of the natural gas and condensate from the Upper Triassic Xujiahe Formation in the northwestern Sichuan Basin indicated that the petroleum was sourced primarily from coaly mudstones and coal rocks that were rich in humic kerogen. K₁ values from the study area average 1.04 and are relatively well correlated, while the K₂ values vary greatly and are relatively poorly correlated. The parent-daughter ratio of the Xujiahe Formation is of the discrete type in the Zitong Sag. The heptane value, isoheptane value and MANGO steady-state catalytic kinetic method indicates that the natural gas is currently in the mature to highly mature stage, with a maturity clearly lower than the measured maturity of the source rocks in the study area and the δ¹³C₁-calculated maturity. The star-plot diagram of light hydrocarbons of natural gas and condensate from the Xujiahe Formation in the Zitong Sag revealed the poor correlation with oil trapped in the same structure but different layers or in the same layer but different structures. This suggested that sand bodies in the reservoirs within the study area were poorly connected and the reservoirs were formed mainly as the result of near-source and short-distance migration and accumulation. Since the early reservoirs in this area have entered the tight evolution stage, natural gas is at different thermal evolution stages, and condensate oil is influenced by the effect of "evaporation and fractionation" of natural gas at different stages of the homologous period, resulting in the discrepancy of the interpretation of some light hydrocarbon parameters.

Separation of macerals in organic-rich source rocks and their geochemical characteristics

XU Jin, ZHANG Caiming, XIE Xiaomin, RUI Xiaoqing

2018, 40(6): 828-835. doi: 10.11781/sysydz201806828

Abstract(1261) PDF-CN(154)

Abstract:
Due to the low abundance, poor brittleness and strong lipophilicity of organic matter in source rocks, kerogen enrichment, freezing in liquid nitrogen-thawing at room temperature and adding ethanol to heavy liquid were applied during the separation of macerals in source rocks. The macerals of botryococcus, alginite, cutinite and vitrinite were successfully separated from source rocks in the Luquan area of the Yunnan Province and the Huadian area of the Jilin Province. Rock-Eval, infrared spectroscopy and activation energy analyses indicated that the hydrocarbon generation capacity of the exinite group is strong and the hydrocarbon generation temperature range is narrow. Different macerals have different structures and generation products. Compared with the exinite group, the hydrocarbon generation capacity of vitrinite is lower, the generation temperature range is wider and the products are dominated by gas. There is a negative correlation between maceral density and hydrocarbon generation capacity.

Geochemical characteristics of Yan 9 crude oil and oil-source correlation in western Jingbian Oil Field, Ordos Basin

ZHANG Hai, LEI Huawei, ZHANG Tao, BAI Yubin

2018, 40(6): 836-842. doi: 10.11781/sysydz201806836

Abstract(1339) PDF-CN(121)

Abstract:
The geochemical characteristics of the Yan 9 reservoir were analyzed by means of petrophysical properties, hydrocarbon group composition, saturated hydrocarbon chromatography and gas chromatography-mass spectrometry in order to clarify the source of oil in the Yan 9 reservoir in the west of Jingbian Oil Field. The geochemical characteristics of Chang 7 source rocks in the study area and the Zhidan area were compared, and the source of Yan 9 oil was studied in combination with regional geological background. The results showed that the saturated hydrocarbon content of Yan 9 crude oil is above 60%, and the n-alkanes are distributed with a single mode with C₂₁ as the main carbon peak, C₃₀ hopane as the dominant biomarker, followed by C₂₉ hopane. Regular steroids are mainly C₂₉, while C₂₇ and C₂₈ are similar, showing an asymmetric "V" distribution. The Yan 9 crude oil has similar geochemical characteristics and unified material source and evolution degree. It is a mature crude oil derived from a source deposited in a weak oxidation-reduction environment under freshwater conditions. Oil-source correlation showed that the source rocks of the Chang 7 reservoir in the Jingbian Oil Field are related to the Yan 9 crude oil, and the geochemical characteristics of the Chang 7 source rocks in the Zhidan area, which is located in the center of the lacustrine basin, are obviously different from the Yan 9 crude oil. The formation of Yan 9 oil is mainly due to the maturation of Chang 7 source rocks in this area. The oils were transported by superimposed sand bodies and fracture systems, migrated vertically to the Yan 9 reservoir, and then migrated laterally to traps for accumulation.

Characteristics of main source rocks and their effectiveness in Papuan Basin

XIN Shiyin

2018, 40(6): 843-848. doi: 10.11781/sysydz201806843

Abstract(996) PDF-CN(92)

Abstract:
The main Jurassic source rocks of the Papuan Basin were systematically studied using the geochemical data of well samples and modern petroleum geological theory and hydrocarbon generation theory. The main Jurassic source rocks were divided into four formations, including the Magobu, Barikewa, Koi-Iange and Imburu formations from base to top, and the Maril Formation in the distal part. These source rocks were mainly distributed in the mid-west part of the basin. The Jurassic source rocks have abundant organic matter, with TOC contents mainly distributed between 0.5% and 2.0%. The TOC content of the Mid-Lower Jurassic is higher than that of the Upper Jurassic. The organic matter in the Jurassic mainly belongs to type Ⅱ₂-Ⅲ, mainly generating gas. The mature threshold in the Papuan Basin is 2 500 m. the Jurassic source rocks are in the low maturity to mature stage, with high maturity to over maturity in certain regions. This paper defined the lowest threshold of TOC content of 1.0% for effective Jurassic source rocks based on the relationship between TOC content and S₁ with the guidance of hydrocarbon generation theory. Combined with the distribution of organic matter abundance and maturity of the Jurassic source rocks, the predicted effective Jurassic source rocks are mainly distributed in the central Fly Platform and the restricted area of the Papuan Fold Belt.

Molecular geochemical evaluation of shale oil mobility: a case study of shale oil in Jiyang Depression

JIANG Qigui, LI Maowen, MA Yuanyuan, CAO Tingting, LIU Peng, QIAN Menhui, LI Zhiming, TAO Guoliang

2018, 40(6): 849-854. doi: 10.11781/sysydz201806849

Abstract(1106) PDF-CN(221)

Abstract:
Shale hydrocarbon potential, shale oil mobility and shale compressibility are three important factors of geological evaluation for shale oil exploration and development. Among them, shale oil mobility is constrained by the pressure system, shale hydrocarbon potential, shale oil composition and occurrence space. Since there were no standardized methods or criteria for shale oil movability evaluation, a combination of multiple parameters (pyrolysis parameter S₁, S₁/w(TOC) and median pore-throat radius) together with exploration and development practice have been used for comprehensive characterization. Based on the experimental analysis of a large number of core samples for shale oil exploration in the Jiyang Depression, a coupling relationship among shale oil molecular composition, shale hydrocarbon potential and shale oil occurrence space was found, and a molecular geochemical evaluation model for shale oil mobility was established. The study revealed that when the ratio of ∑nC_20^-/∑nC_21⁺ was<1, shale pore throat radius was generally>20 nm. Under this condition, pyrolysis S₁ was usually>3 mg/g and S₁/w(TOC) was>100. The ratio of ∑nC_20^-/∑nC_21⁺ basically remained constant with the increase of S₁, the ratio S₁/w(TOC) and shale pore throat radius. This indicated that when shale pore throat radius is large, hydrocarbon molecular diffusion is not affected by diffusion energy barriers, and shale oil molecule occurrence in pore throats is relatively homogeneous, so shale oil has a good fluid mobility. When the ratio of ∑nC_20^-/∑nC_21⁺ was>1, shale pore throat radius was usually<20 nm, pyrolysis S₁ was commonly<3 mg/g, and the ratio of S₁/w(TOC) was<100. The ratio of ∑nC_20^-/∑nC_21⁺ was increasing quickly with the decrease of S₁, S₁/w(TOC) and shale pore throat radius. It indicated that when the shale pore throat radius becomes small, diffusion energy barriers limited the diffusion of macromolecular hydrocarbon components in pore throats, thus shale oil has a poor fluid mobility and low molecular weight hydrocarbon is the main constituent to flow easily. In such a condition, shale has a poor content of free oil. The lowest limit of pore-throat radius for shale oil flow in the Jiyang Depression is approximately 20 nm.

Optimization of compound-specific hydrogen isotope analysis of natural gas

ZHANG Wenlong, HUANG Ling

2018, 40(6): 855-858. doi: 10.11781/sysydz201806855

Abstract(1008) PDF-CN(85)

Abstract:
The conditioning method has an important influence on the compound-specific analysis results of hydrogen isotope ratios. The effects of three methods (injection of n-hexane or methane in the inlets, the reverse injection of methane) on the determination of hydrogen isotope values were investigated and compared. The results showed that the method of reverse injection of methane before each sample analysis can ensure the consistency of conditioning in the pyrolysis furnace tube, and can provide the best repeatability and accuracy of the compound-specific hydrogen isotope determination of natural gas.

Controls and quantitative characterization of stress sensitivity for coal seams

WANG Jinghui, MEI Minghua, LIANG Zhengzhong, WANG Huajun

2018, 40(6): 859-863. doi: 10.11781/sysydz201806859

Abstract(858) PDF-CN(115)

Abstract:
The stress sensitivity of coalbed methane reservoirs is strong, which has an important influence on the development of coalbed methane. Natural coal samples from different blocks were used to carry out stress sensitivity experiments, and two parameters, stress sensitivity coefficient and permeability damage coefficient were applied to evaluate the degree of stress sensitivity of coal samples. The stress sensitivity effects of coal rank, permeability and the gas pressure of a coal reservoir were studied. The results showed that when R_o is lower than 1.7%, the lower the coal rank is, the greater the degree of stress sensitivity is and the higher the extent of the permeability damage. When R_o is higher than 1.7%, the higher the coal rank is, the greater the degree of stress sensitivity is and the higher the permeability damage is. The empirical formula, put forward by this paper, between initial permeability and stress sensitivity coefficient can be used to predict the stress sensitivity coefficient of coal samples, which is convenient for pilot application. The lower the pressure of a gas reservoir is, the higher the permeability, which is advantageous for CBM development. However, lower gas pressure results in a slightly higher stress sensitivity coefficient and permeability damage coefficient, so avoiding stress sensitivity is important.

Physical simulation of volumetric charging of volcanic rock: case study of volcanic rock in Yingcheng Formation of Xujiaweizi Fault Depression in Songliao Basin

ZHANG Xuejuan, RONG Pengfei, LU Shuangfang, ZHANG Xi, GUO Tianran, WANG Min

2018, 40(6): 864-870. doi: 10.11781/sysydz201806864

Abstract(909) PDF-CN(92)

Abstract:
Full-diameter volcanic rock core samples of the Yingcheng Formation in the Xujiaweizi Fault Depression of the Songliao Basin were used in a transparent experimental device with pressure resistance. An initial filling pressure was selected to carry out a constant volume exhaust gas filling experiment. Experimental results showed that the crack-type medium needs a certain opening pressure and opening time to have high-efficiency transport ability, and once the crack is opened, even if the charging pressure is lower than the opening pressure, it still has the ability to transport until the charging pressure difference drops to zero. Among the porosity-permeability-type heterogeneous rock samples, gas migration path can be expressed as a finger plunging feature in medium porosity and permeability core. However, in the high porosity and permeability volcanic rock medium, a regular curtain-type periodic migration process of each pore-permeating unit during the filling process was observed. Overall, the constant volume filling pressure and decay time has an attenuation feature with an exponential relationship, and with the attenuation of filling pressure, natural gas migration speed is accompanied by the curtain characteristics of wave fluctuation. As the filling pressure continuously reduces, the range of curtain transport paths gradually reduces.

Application of INPEFA technology to sequence stratigraphy of the third member of Funing Formation, Nanhua block, Qintong Sag, North Jiangsu Basin

YUAN Ye, WANG Li, XIE Ruijie

2018, 40(6): 871-876. doi: 10.11781/sysydz201806871

Abstract(791) PDF-CN(118)

Abstract:
The maximum entropy spectrum analysis technique provides the frequency trend line (INPEFA curve) by analyzing the synthetic prediction error filtering of logging curves, and using the trend turning point of different amplitude of the INPEFA curve to identify the interface of different order sequences.Through the INPEFA treatment of the GR curves of the third member of Funing Formation in the Nanhua block in the Qintong Sag of the North Jiangsu Basin, the Ⅲ and IV oil groups were divided into 13 five-level sequences, and then the sand body connectivity among three wells with close distances within the block was compared in an isochronous framework established by INPEFA curves. Comparing the sand body connectivity, it was concluded that there were two sand layer groups and oil layer groups connected in the small layer. The logging curves processed by INPEFA technology can extract the characteristics of cyclic trends hidden in conventional logging curves. According to the INPEFA curves with similar trends in the three wells, the sedimentary environment in this area changed roughly the same, from regression to transgression.

Quantitative analysis of reservoir-cap rock assemblages of the first member of Sanduo Formation and prediction of favorable regions in Gaoyou Sag, North Jiangsu Basin

DING Jianrong, LI Chuhua, MA Yingjun

2018, 40(6): 877-885. doi: 10.11781/sysydz201806877

Abstract(972) PDF-CN(111)

Abstract:
Overall, the reservoir forming conditions are good in the E₂s₁ (the first member of Sanduo Formation) of the Gaoyou Sag,North Jiangsu Basin. Sandstones were well developed. Reservoir-cap rock assemblage is one of the key factors controlling hydrocarbon accumulation. For the sake of evaluating reservoir-forming conditions and favorable exploration regions, it is important to analyze effective reservoir-cap rock assemblage and predict favorable regions. It was considered that there are multiple reservoir-cap rock assemblages, which are important factors controlling hydrocarbon accumulation and enrichment of each submember in the E₂s₁. Firstly, according to the degree of mudstone stability, the paper qualitatively divided the reservoir-cap rock assemblage into two sorts:regional and local. Secondly, in order to recognize effective reservoir-cap rock assemblage more accurately and based on the qualitative analysis, a quantitative oil reservoir analysis was completed. Through analyzing the relationship between sandstone ratio of the hydrocarbon and upper submembers with hydrocarbon accumulation, the boundary between reservoir rock and cap rock was confirmed, a quantitative evaluation threshold was built, and three types of effective reservoir-cap rock assemblage were identified (lower reservoir and upper cap rock assemblage, interior reservoir and cap rock assemblage, and mixed reservoir and cap rock assemblage). Thirdly, based on the quantitative analysis, the favorable regions of effective reservoir-cap rock assemblage were predicted. Several regions have great exploration potential, such as the eastern Huangjue to western Shaobo area in the field of both structural and subtle traps, which have achieved good results in exploration.

Comments on carbonate determinism in oil generation

HE Zhigao

2018, 40(6): 886-890. doi: 10.11781/sysydz201806886

Abstract(1146) PDF-CN(178)

Abstract:
In the petroleum geology sciences, since the controversy over the theory of oil generation, some inorganic theorists have questioned the criticism of the various sources and defects of the organic origin and advocated an inorganic source. Organic theorists have never systematically responded by geochemistry because the old organic cause theory itself does have some problems. Today, a new theory of oil genesis has matured, namely "oil generation driven by microorganism and carbonate in a waterlogged and closed system". This new theory has made a new upgrade:oil generation by carbonate determinism. This paper was divided into two parts. In the first part, 9 points of skeptical comment were put forward on the theory of petroleum inorganic genesis. The second part briefly explained the role of carbonate synergistic microorganisms in the theory of "oil generation driven by microorganism and carbonate in a waterlogged and closed system". On the theoretical basis, the paper proved that oil could not be generated in any sedimentary basins without ancient carbonate source sediments, defined as "carbonate determinism".

2018 Vol. 40, No. 6

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