石油实验地质

2018, 40(3): .

Abstract(377) PDF-CN(104)

Abstract:

Structure and sedimentary characteristics of the Meso-Cenozoic basin group along the Yangtze River in the Lower Yangtze region

XU Xi, ZHU Xiaoying, SHAN Xipeng, XIAO Mengchu, SUN Lianpu, GAO Shunli

2018, 40(3): 303-314. doi: 10.11781/sysydz201803303

Abstract(1786) PDF-CN(405)

Abstract:
The basin group along the Yangtze River is an important part of the Meso-Cenozoic petroliferous basins in the Lower Yangtze region, which is also an important window for the study of the structure and tectono-sedimentary evolution of the Meso-Cenozoic basins in East China. There are nine relatively independent faulted basins from west to east in the Yangtze River's middle and lower reaches, including Poyang, Qianshan, Wanjiang, Quanjiao, Wuwei, Jurong-Nanling, Changzhou-Xuancheng, Liyang and Pinghu basins, which comprise a basin system or group in the plane, named the Lower Yangtze basin group. Sedimentary filling in the basins was divided into two stages including faulting from the Late Cretaceous to the Paleogene, and depression from the Neogene to the Quaternary. The former stage is characterized by the sedimentation of fluviolacustrine and delta facies, while the latter stage is marked by the deposition of fluvial facies. The fault basin system formed in the Late Oligocene, and a unified depression system formed in the Neogene along the Yangtze River. Due to the Neogene differential deformation, the basinal strata were differentially denuded, forming the modern geological setting of the sedimentary basins.

Characteristics of organic pores in Middle and Upper Permian shale in the Lower Yangtze region

CAO Taotao, DENG Mo, LUO Houyong, LIU Hu, LIU Guangxiang, HURSTHOUSE Andrew Stefan

2018, 40(3): 315-322. doi: 10.11781/sysydz201803315

Abstract(1671) PDF-CN(232)

Abstract:
A set of transitional shale reservoirs developed in the Middle and Upper Permian strata in the Lower Yangtze region, with a maceral composition significantly different from that of marine shale. Organic petrology, scanning electron microscopy, field emission scanning electron microscopy in combination with argon ion polishing, gas-filled porosity and mercury intrusion experiments were conducted in order to reveal the characteristics of organic pores and their influencing factors. The results showed that organic pores were well developed overall in the Middle and Upper Permian shale, but have significantly different characteristics in different maceral grains. Vitrinite generally has no or rare pores developed, solid bitumen could produce a small quantity of large-scale isolated pores, and sapropelinite usually contains a large number of small pores, which is the main contributor to organic porosity. Pyrite and/or clay minerals could be mixed with organic matter and then enhance the development of pores in organic matter grains, which may be related to the effect of pyrite and clay minerals on organic matter generation and decomposition. Although there is a positive relationship between specific surface area and TOC content, the relationship of porosity with TOC content is rather complex. The TOC content has a positive relationship with porosity for the Middle and Upper Permian shale when w(TOC)<6.16%, whereas porosityis generally low and has a slight decreasing trend with increasing TOC content when w(TOC)>6.16%. The pore size distribution also revealed that the high TOC content shale has lower meso-macropore volume than the shale with a low TOC content. The characteristics of pore development in the Middle and Upper Permian shale illustrated that solid bitumen and hydrogen-depleted components increased with increasing TOC content, and these macerals would fill in the mineral intergranular pores and reduce the overall space of shale. Meanwhile, with higher TOC content, the shale is more likely to be compacted, resulting in the collapse of mesopores and macropores, further reducing the porosity of shale.

Reservoir characteristics and controlling factors in the contact metamorphic zone of hypabyssal intrusive rocks in the Qintong Sag, Northern Jiangsu Basin

WU Jun, CHEN Kongquan, ZHANG Feng, SHEN Junjun, LIU Jinshuai, TAN Jing

2018, 40(3): 323-329. doi: 10.11781/sysydz201803323

Abstract(2030) PDF-CN(294)

Abstract:
Reservoir characteristics and controlling factors in the contact metamorphic zone of hypabyssal intrusive rocks are of a great significance for the exploration and development of magmatic oil reservoirs. The contact metamorphic zone of hypabyssal intrusive rocks was well preserved in the Shuaiduo-Maoshan areas of the Qintong Sag, Northern Jiangsu Basin, and is an ideal area to understand this mechanism. Systematic core and drill cuttings observations, well logging interpretation and borehole-seism-modulus integration techniques were conducted to evaluate spatial distribution regularities and dissect the characteristics of reservoir development in a typical contact metamorphic zone. Some favorable reservoirs in the contact metamorphic zone of intrusive rocks in the Qingtong Sag were predicted. The studies showed that wall rocks were altered by the influence of intrusive rocks, forming the contact metamorphic zone of intrusive rocks. The contact metamorphic zone has the characteristics of high natural gamma, medium sonic time difference, medium natural potential and high resistivity on logging curves. The contact metamorphic zone generally distributed above and below the intrusive rocks, and has a positive correlation with the thickness of intrusive rocks. In addition, the thickness of altered mudstones in the contact metamorphic zone is the main factor affecting the distribution of high quality reservoirs, and the high-quality reservoirs in the contact metamorphic zone near to volcanic sills are favorable for hydrocarbon accumulation.

Hydrocarbon accumulation characteristics of the 2nd member of Weizhou Formation in the Weixinan Sag, Beibu Gulf Basin

ZOU Mingsheng, ZENG Xiaoming, WU Bibo, WANG Bin, HUANG Dongmei, GAO Ling

2018, 40(3): 330-336. doi: 10.11781/sysydz201803330

Abstract(1379) PDF-CN(183)

Abstract:
The Weixinan Sag in the Beibu Gulf Basin of the South China Sea is a hydrocarbon-rich sag. However, currently limited oil and gas were found in the 2nd member of Weizhou Formation, and the hydrocarbon accumulation characteristics and laws were unclear, which restricted next exploration direction. The main controlling factors and accumulation rules of oil and gas in the 2nd member of Weizhou Formation were studied based on laboratory tests and drilling and seismic data. The crude oil of Weizhou Formation was mainly originated from the thick oil shale in the central and upper parts of the 2nd member of Liushagang Formation. The lacustrine mudstones in the upper part of the 2nd member of Weizhou Formation provided regional cap rocks. Oil and gas were mainly distributed close to the source rock connected faults of the no.2 fault zone, which were the keys for hydrocarbon accumulation. Fault block traps with roof ridge structures generated by reverse faults and SGR>0.64 and SSF<1.70 at fault sections were favorable for hydrocarbon accumulation, providing an exploration target and direction for the next step.

Micro-pore characteristics of shale from Wufeng-Longmaxi formations in Pingqiao area, Sichuan Basin

WANG Yunhai

2018, 40(3): 337-344. doi: 10.11781/sysydz201803337

Abstract(1661) PDF-CN(350)

Abstract:
The microscopic pore characteristics of shale from the lower Wufeng-Longmaxi formations in the Pingqiao area of the Sichuan Basin were studied using argon ion polished sample scanning electron microscopy and nitrogen adsorption-desorption experiments. Organic-rich siliceous shale and carbonaceous shale micro-pores are dominated by organic pores and micro-cracks. The pore structure is relatively complex, with rich pore morphology and a wide range of pore sizes. Argon ion polishing scanning electron microscopy showed that the organic pores are mainly thin and partly belong to micro-pores. Nitrogen adsorption-desorption experiments showed that the shale has narrow parallel plate-like holes, a small number of conical plate holes and wedge-shaped holes with a poor connectivity, and regular open round holes and ink bottle-shaped holes with open ends. The specific surface area measured by nitrogen adsorption-desorption experiments was 9-32.6 m²/g, with an average of 18.0 m²/g, which was low. The pore diameters measured by the BET method were 3.23 to 4.35 nm, and the average pore volume by the BJH method was 0.016 5 cm³/g. The fine meso-pores were dominant, and they were biased toward the micro-pore boundary. According to the comprehensive analysis, the microscopic pores of shale reservoirs in the study area are mainly mesoporous, and meso-pores and micro-pores contribute most of the specific surface area.

Reservoir characteristics and main controlling factors of Yingcheng-Shahezi formations in southeast ramp region of Lishu Fault Depression, Songliao Basin

HAN Zhiyan, ZHOU Zhuoming, YANG Hao, SONG Zhenxiang

2018, 40(3): 345-352. doi: 10.11781/sysydz201803345

Abstract(1418) PDF-CN(204)

Abstract:
The sandstone reservoirs of the Lower Cretaceous Yingcheng-Shahezi formations in the Lishu Fault Depression of the Songliao Basin have a strong heterogeneity and a low exploration success rate. Through core observation, thin section identification and quantitative statistics, porosity and permeability analysis, mercury intrusion, etc., it was concluded that the Yingcheng-Shahezi formations in the southeast ramp of Lishu Fault Depression are dominated by pebbly sandstones, followed by fine-grained and medium-grained sandstones, with low contents of coarse debris and quartz, and low compositional and structural maturities. The main components are feldspathic lithic sandstones, lithic sandstones, and lithic feldspar sandstones, with a small amount of feldspar sandstones. Feldspars and rock debris are in high content, and the interstitial material is mainly argillaceous and calcite. The Yingcheng-Shahezi formations have an ultra-low porosity and an ultra-low permeability with a strong heterogeneity. They consist of primary intergranular pores, secondary dissolved pores and fissures, mainly primary pores, and fractures in some areas. The pore development of reservoirs is controlled by sedimentary environment and diagenesis, and the role of late tectonic fractures cannot be ignored. The primary pores were greatly reduced by cementation and mechanical compaction, while dissolution and structural rupture effectively improved the physical properties of the reservoir. In particular, the late tectonic fissures produced different types of fractures and increased porosity and permeability, which may be one of the important reasons for the formation of high-yield oil and gas fields in the Qinjiatun and Jinshan areas of the southeast ramp.

Distribution and significance of Middle Ordovician Yijianfang Formation in Shuntuoguole lower uplift, Tarim Basin

SHANG Kai, LÜ Haitao, CAO Zicheng, HAN Jun, GONG Wei, HUANG Cheng

2018, 40(3): 353-361. doi: 10.11781/sysydz201803353

Abstract(1221) PDF-CN(156)

Abstract:
The Middle Ordovician Darriwilian stage conodonts have been recovered from key wells in the Shuntuoguole lower uplift, Tarim Basin. They are Eoplacognathus suecicus, Pygodus anitae and Pygodus serrus in ascending order. These fossil provide the basis for the division and correlation of the Yijianfang Formation which is one of the main exploration targets. The characteristics of the Yijianfang Formation were analyzed based on isotopic strati-graphy, lithologic and petrophysical features and seismic data at the same time. On this basis, the distribution of the Yijianfang Formation in this district was analyzed through the comparison of the stratigraphic division, precise tracking and interpretation of seismic horizons. This formation is widely distributed in the Shuntuoguole lower uplift, with a thickness of 140-220 m. It has the largest thickness (> 200 m) in the SN1 to ST1 well area. There is no erosion unconformity between the Yijianfang Formation and the Qiaerbake Formation, which did not allow the development of paleo karst in the Middle Caledonian.

Characteristics of movable fluids and controlling factors in different flow units of Chang 8₁ reservoir in Maling oil field, Ordos Basin

LI Pan, SUN Wei, YAN Jian, GAO Yongli, ZHE Wenxu, DU Kun

2018, 40(3): 362-371. doi: 10.11781/sysydz201803362

Abstract(1406) PDF-CN(173)

Abstract:
The Chang 8₁ reservoir of the Maling oil field in the Ordos Basin has low porosity and low permeability. The quality of oil and gas reservoirs is constrained by the strong heterogeneity of its permeability. We analyzed the characteristics of its microscopic pore structure by conducting an NMR experiment and microcosm experiments including constant speed mercury injection, high pressure mercury injection, image granularity, and casting lamella. We then divided the flow units into 4 classes E, G, M and P, using SPSS data analysis software on the basis of 5 chosen parameters, including sand thickness, porosity, permeability, oil saturation and flown zone exponent. We analyzed the microscopic pore structure characteristics in different types of flow unit and the impacts on movable fluid saturation. The results showed that there are obvious differences in the microscopic pore structure characteristics in different flow units, which are the main factors that caused different movable fluid saturation. The distribution and size of pore throat radius played a crucial role. Production performance data demonstrated that classes E and G acquired the highest capacity in the oil and gas field development. Reasonable and effective development programs should be implemented according to the microscopic pore structure characteristics of different flow units.

Basin types and hydrocarbon distribution in salt basins in the South Atlantic

LIU Jingjing, WU Changwu, DING Feng

2018, 40(3): 372-380. doi: 10.11781/sysydz201803372

Abstract(1789) PDF-CN(236)

Abstract:
The salt basins in the South Atlantic are rift-passive continental margin superimposed basins.These basins have the same tectonic evolution history and similar characteristics of stratigraphic development, but the hydrocarbon distribution is extremely uneven.Based on the further subdivision of basin type, this paper discussed the distribution of hydrocarbon in the salt basins. First, according to the characteristics of stratigraphic structure which was deposited during the rift stage, the salt basins in the South Atlantic were divided into two kinds of basin:rift strata with characteristics of depressions and uplifts, and rift strata with monoclinic characteristics. According to the characteristics of stepped faults during the rift stage and the sedimentary characteristics during the stage of passive continental margin, each type can be subdivided into two subtypes. Second, based on the analysis of regional petroleum geological conditions, there are three hydrocarbon accumulation combinations in the study area, including pre-salt, post-salt Cretaceous and Tertiary hydrocarbon accumulation combinations, and this paper outlines accumulation models and the main controlling factors.Finally, from the point of view of the basin type, the difference of hydrocarbon accumulation conditions in different basins was pointed out, and the differences of hydrocarbon distribution in different basins were discussed. These results will guide further oil and gas exploration in the salt basins in the South Atlantic.

Evaporative fractionation and biodegradation impacts on a complex petroleum system: QHD29-2 oil field, Bohai Sea area

NIU Chengmin, WANG Feilong, TANG Guomin, YAN Ge, ZHAO Guoxiang

2018, 40(3): 381-388. doi: 10.11781/sysydz201803381

Abstract(1278) PDF-CN(187)

Abstract:
By studying the tectonic background of QHD29-2 oil field and the geochemical characteristics of oil and gas and its source rocks, the dissimilarity of crude oil physical properties was discussed from the perspective of evaporative fractionation and biodegradation. Oil source comparison confirmed that the oils in Paleogene and Neogene had the same source. However, there were significant differences in light hydrocarbon composition, family composition and the chromatographic distribution of saturated hydrocarbons, indicating that they had experienced a strong evaporative fractionation. Combined with the analyses of source rock thermal evolution, accumulation stage and fault activity history, it was believed that the intrusion of mantle-derived CO₂ gas had caused evaporative fractionation in the area. The evaporative fractionation and biodegradation jointly controlled crude oil physical properties in the reservoir. Evaporative fractionation and biodegradation were the main factors controlling the differences of crude oil physical properties in reservoirs, and the differences were mainly controlled by evaporative fractionation, whereas, the oil in shallow reservoirs was controlled by both evaporation and biodegradation. Extra-heavy, light, condensate and heavy oils distributed in sequence from deep to shallow reservoirs. The two mechanisms had an impact on the same reservoir simultaneously. The early reservoirs in deep formations were affected by evaporative fractionation. After the shallow reservoirs of the post-accumulation were biodegraded, they were continuously charged in the late stage of the pre-existing reservoir.

Degradation characteristics of propane in shale rocks and its implication to shale gas composition

XU Jianbing, LIANG Yungan, DENG Qian, CHENG Bin, LIAO Zewen

2018, 40(3): 389-396. doi: 10.11781/sysydz201803389

Abstract(1397) PDF-CN(196)

Abstract:
Propane and shale samples taken from the same well and different depths in the Longmaxi Formation in the Sichuan Basin were selected to carry out different series of simulation experiments in order to investigate the influence of the degradation of small molecular hydrocarbons on the composition of shale gas in the shale during the over-mature stage. The constant temperature thermal simulation experiments of a gold tube-restricted system were carried out on C₃H₈, C₃H₈ + shale, C₃H₈ + shale + water at 360℃ and 50 MPa for 72, 216, 360, 720 h. Other pyrolysis experiments were performed using C₃H₈ and C₃H₈ + shale samples at 400, 450, 500 and 550℃ with a pressure of 50 MPa for 72 h in order to increase the degradation degree of C₃H₈. The results showed that the CH₄, C₂H₆ yields and the CH₄/C₂H₆ ratio of C₃H₈ + shale at 360℃ are higher than those of C₃H₈ alone. The experiments with S1 shale rock which contains more clay minerals generated more CH₄ and C₂H₆ than those with S2 rock sample, and generally showed higher CH₄/C₂H₆ ratios. After increasing the simulation temperature, the conversion of C₃H₈ was significantly increased. The yields of CH₄ and C₂H₆ in the C₃H₈ + shale experiment were all higher than those in the control experiment, and the yield of CH₄ was higher than that of C₂H₆. These results indicated that clay minerals can catalyze C₃H₈ degradation and produce more CH₄. The yields of CH₄ and C₂H₆, and the CH₄/C₂H₆ ratio from the hydrous experiments were higher than those from anhydrous experiments, which indicated that water can promote the cracking of C₃H₈ to produce more CH₄. The positive effect of clay mineral and water in shale on C₃H₈ cracking increased the dryness index of shale gas. The degradation of small hydrocarbon molecules had an important influence on the composition of shale gas particularly in high-to over-mature shale rocks. It seems that water played a significant role and its effect on the evaluation of shale gas reserve should be thoroughly investigated especially for high-to over-mature shale rocks.

Characteristics of Jiufotang source rock and its relationship to hydrocarbon enrichment, southern Songliao Basin

CHENG Jian, DUAN Tiejun, XIANG Hong, SONG Zaichao, WEI Qingliang

2018, 40(3): 397-402. doi: 10.11781/sysydz201803397

Abstract(1825) PDF-CN(193)

Abstract:
Source rock and crude oil samples from the Jiufotang Formation in the Zhangwu and Changtu depressions in the southern Songliao Basin were analysed for TOC content, pyrolysis yield, rock group composition, carbon isotope and biomarkers. The oil in the Zhangwu Depression was mainly sourced from the lower part of Jiufotang Formation, while that in the Changtu Depression mainly derived from the upper part of Jiufotang Formation. The Jiufotang source rocks in other depressions with industrial oil and gas discoveries in the study area were also studied, indicating that the Jiufotang source rocks were the main source rocks in the region, with high abundance, multiple types, and low evolution degree. The source rock distribution has a good relationship with the degree of hydrocarbon enrichment. Various factors such as structural evolution of the depression, sedimentary environment, burial depth, and later-stage preservation conditions result in more hydrocarbon production in the lower part of Jiufotang Formation relative to those in the upper part. Maturity is an important factor affecting source rocks. The development and distribution of high-quality source rocks in the Jiufotang Formation were determined. Finding a good source and reservoir configuration and appropriate near-source traps lead to favorable exploration directions in the southern Songliao Basin.

Bio-precursor characterization and hydrocarbon generation potential of shale in Eocene Huadian Formation, Huadian Basin

WANG Qin, XIE Xiaomin, TENGER Boltsjin, RUI Xiaoqing, XU Jin

2018, 40(3): 403-409. doi: 10.11781/sysydz201803403

Abstract(1667) PDF-CN(175)

Abstract:
A set of high-quality oil shales developed in the Eocene Huadian Formation in the Huadian Basin, Jinlin Province. Twenty-two rock samples were collected from the Guanglangtou district for bio-precursor and hydrocarbon generation potential analyses. Two samples containing different types of algae were chosen for thermal simulation. The Huadian shale has a high TOC content (10.6%-39.6%) and a high Rock-Eval hydrogen index (HI) value (887 mg/g), suggesting a good hydrocarbon generation potential. Detailed bio-precursor analyses demonstrated that the organic matter was dominated by phytoplankton, such as lamalginite and telalginite (including botryococcus and diatom), and fragments from benthic macroalgal rhodophyte were found in some thin layers. Higher plants mainly include detrital vitrinoids, fungi and detrital plastids, and sporophytes. The sample HD-20 with more benthic algae produced the maximum amount of hydrocarbon (427 mg/g) at 400℃ (R_o=1.02%), while the sample HD-21 dominated by planktonic algae produced the maximum amount of hydrocarbon (909 mg/g) at 425℃ (R_o=1.18%). Thermal simulation experiments showed that the sample HD-21 had a much higher hydrocarbon generation potential than the sample HD-20, even though the TOC content of HD-20 was much higher, indicating that the benthic macroalgal macerals have a much lower capacity to generate oil when thermally mature.

Geochemical features and oil-source correlation of crude oils from JZ20 oil field on the northern margin of Liaoxi Uplift,Bohai Bay Basin

TIAN Derui, WU Kui, ZHANG Rucai, PAN Wenjing, WANG Xin

2018, 40(3): 410-417. doi: 10.11781/sysydz201803410

Abstract(1334) PDF-CN(174)

Abstract:
The Liaoxi Uplift is one of the regions with the highest level of exploration in the Liaodong Bay area of the Bohai Sea. Geochemical analyses were carried out on crude oil samples from the Shahejie and Dongying formations in the JZ20 oil field on the northern margin of Liaoxi Uplift. The physical properties, hydrocarbon group composition, maturity and biomarker characteristics of crude oil were studied, based on which an oil-source correlation was made. The crude oil is light with a low maturity and low sulfur content. The saturated hydrocarbon chromatograms of the oil are distributed fully, indicating no biodegradation. The organic matter source is mixed with a minor terrigenous input to the crude oil in the Shahejie Formation and a significant terrigenous organic matter input to the crude oil in the Dongying Formation. The source rock was deposited in an anoxic to suboxic and brackish or saline water environment. Crude oil of the Shahejie Formation originated from the third and the first members of Shahejie Formation in the Liaoxi Sag. Crude oil of the Dongying Formation originated from the third member of Shahejie Formation in the Liaoxi Sag and the third member of Dongying Formation in the Liaozhong Sag. In addition, crude oil of the Dongying Formation is characterized by a double-sag hybrid source hydrocarbon supply.

Analysis method and geological significance of C₅-C₇ light hydrocarbons in natural gas hydrate in permafrost, Qilian Mountain

ZHANG Min, HE Yu, CHEN Zulin, GONG Jianming

2018, 40(3): 418-423. doi: 10.11781/sysydz201803418

Abstract(977) PDF-CN(130)

Abstract:
A sample introduction device of vacuum thermal desorption, cold on-column and zero-pressure was built for the identification of C₅-C₇ light hydrocarbons in gas hydrate. On the basis of previous Kováts index research, 27 compounds of C₅-C₇ light hydrocarbons were identified, which provided a foundation for the geochemical study on light hydrocarbons in gas hydrate in the Juhugeng mining area, Muli coal field, Qilian Mountain. Two genetic types of gas hydrate in the Muli permafrost were divided into three types, including oil-type, coal-type and mixed-type gas based on the methylcyclohexane index. The mixed-type gas predominates in the Muli permafrost, while the other two types are in the minority.

Optimization of hydrocarbon migration parameters and identification of migration pattern

LIU Hua, JING Chen, LIU Yali, YUAN Feifei, LU Hao

2018, 40(3): 424-430. doi: 10.11781/sysydz201803424

Abstract(1158) PDF-CN(319)

Abstract:
The change ratio of geochemical parameters was proposed and applied in the Bonan Subsag, Zhanhua Sagto quantitatively identify the migration dynamics and patterns of petroleum in overpressured basins. Based on oil source correlation, migration pathway recognition and pressure distribution, the method of the change ratios of geochemical parameters was selected and calculated to identify the range of overpressure-driven, buoyancy-driven or complex driven oil reservoirs. Migration dynamics, patterns and function boundariesin the process of hydrocarbon migration can be determined. This method can quantitatively characterize and recognize hydrocarbon migration patterns. However, influenced by the changing characteristics of parameters, it is applicable to identify the patterns of hydrocarbon migration for the same origin, the same path and the same period. Affected by differential structural background, hydrocarbon propertiesand migration pathway,the determining boundary of the change ratio of geochemical parameters has differentiation and regional specificityin application.

Detailed classification and evaluation of reserves in fracture-cavity units for carbonate fracture-cavity reservoirs

LIU Yao, RONG Yuanshuai, YANG Min

2018, 40(3): 431-438. doi: 10.11781/sysydz201803431

Abstract(953) PDF-CN(161)

Abstract:
The previous classification and evaluation results of proven reserves of carbonate fracture-cavity reservoirs cannot meet the needs of detailed reservoir development and oil recovery improvement. Based on the identification of fracture and cavity, using both static and dynamic methods, we proposed a method for the detailed classification and evaluation of reserves in fracture-cavity units in view of the conditions of reserve effective controlling and producing. The reserves of fracture-cavity units were classified into uncontrolled, well controlled but unconnected, connected but difficult-to-produce, and connected and easy-to-produce reserves. The results were applied to a comprehensive strategy such as completed well deployment, injection-production adjustment and flow channel adjustment, which effectively improved production efficiency and development effect.

Complex fault interpretation of buried hills: A case study of Zhuanghai region in Jiyang Depression, Bohai Bay Basin

WU Xiaohe

2018, 40(3): 439-447. doi: 10.11781/sysydz201803439

Abstract(1273) PDF-CN(141)

Abstract:
The Zhuanghai oil field is located in the north of the Jiyang Depression, Bohai Bay Basin. Drilling data illustrated that the pre-Tertiary formations of the Zhuanghai area are rich in oil. However, complicated structures developed in the pre-Tertiary formations with unclear fault directions and distributions, which made the exploration of the pre-Tertiary structures very difficult. The nature of faults was determined by considering the mechanism of fault evolution. The key techniques for the interpretation of faults of different natures were studied to accurately describe the fault system and deduce fault development patterns to define the structural features. The Zhuanghai area has experienced several stages of deformation, including regional uplift, stable structure, extrusion, stable structure, tension, tense-shearing and compresso-shearing. The tectonic compressions during the Indosinian and the late Yanshanian periods formed thrust tectonics, which laid the foundation for buried hills. The extensional strike-slips in the Himalayan period made the buried hills more complicated. A fault interpretation was made, mainly focusing on reversed faults. The derivative of stratigraphic thickness change rate and dip can be calculated to interpret reversed faults. Time slices and fault planes were combined to interpret strike-slip faults. Coherent cube, ant-colony and 3D visualization were combined to interpret normal faults. The Paleozoic in the Zhuanghai area developed NNE-trending reverse faults and EW-trending extensional faults, with thrust, negative reversal and strike-slip fault types, showing a complex pattern of "barriers and depressions".

Correction and interpretation application of key parameters of Waxman-Smits model: A case study of SHW area in North Jiangsu Basin

JIANG Aming, LI Qiuzheng

2018, 40(3): 448-453. doi: 10.11781/sysydz201803448

Abstract(1476) PDF-CN(201)

Abstract:
Due to the additional conductivity of clay minerals, oil reservoir resistivity decreases obviously in argillaceous siltstone reservoirs, which gives a great uncertainty for the calculation of oil saturation. A combination of the actual data of the 3rd member of Funing Formation in the SHW area of North Jiangsu Basin allowed some key factors of the Waxman-Smits model, such as the equivalent conductivity (B) and the exchange concentration (Q_v) of cations, to be corrected with a large amount of experimental data. A detailed quantitative evaluation of reservoirs was carried out with the corrected oil saturation interpretation model. Compared with the conventional Archie formula, the accuracy of oil saturation calculation was greatly improved, which gave a good solution to the problem of the identification of argillaceous siltstone reservoirs, and provided a reference for the determination of old field potential.

Hydrocarbon generation simulation of low-maturity shale in Shanxi Formation, Ordos Basin

GAO Dongchen, GUO Chao, JIANG Chengfu, ZHANG Lixia, WANG Hui, SHI Peng, CHEN Yiyi

2018, 40(3): 454-460. doi: 10.11781/sysydz201803454

Abstract(1358) PDF-CN(229)

Abstract:
Low-maturity organic-rich shale from the Paleozoic Shanxi Formation in the eastern margin of Ordos Basin was chosen for pyrolysis simulation in order to find out hydrocarbon generation laws and its influencing factors, and to reveal the hydrocarbon generation potential of shale. A pyrolysis system of sealed gold tubes in high pressure vessels was employed to conduct pyrolysis experiments at two heating rates of 20℃/h and 2℃/h under a constant confining pressure of 50 MPa. The yields of gaseous hydrocarbons and liquid hydrocarbons, and the carbon isotopic compositions of gaseous hydrocarbons were measured. The experimental products at different heating rates were analyzed, the carbon isotope characteristics and genesis were discussed, and a hydrocarbon generation model of Shanxi group was established. The research demonstrated that (1) the relatively low heating rate was favorable for the generation of hydrocarbon gas; (2) at the relatively low heating rate, both yield of liquid hydrocarbon and temperature of maximum yield were low; (3) the temperature had a significant effect on the carbon isotope of pyrolysis gas. However, the effect of heating rate on the carbon isotope of pyrolysis gas was not obvious. A shale hydrocarbon generation model was established according to the thermal simulation experiment. The results of hydrocarbon generation simulation indicated that the shale in the Shanxi Formation in the Ordos Basin had a good potential of hydrocarbon generation.

2018, 40(3): 460-460.

Abstract(389) PDF-CN(113)

Abstract:

2018, 40(3): 461-461.

Abstract(374) PDF-CN(123)

Abstract:

2018 Vol. 40, No. 3

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