石油实验地质

2019, 41(5): .

Abstract(317) PDF-CN(108)

Abstract:

Reasons for the failure of petroleum exploration wells from the process of hydrocarbon accumulation

JIN Qiang, CHENG Fuqi, WANG Qiutong, WANG Tongshan

2019, 41(5): 621-629. doi: 10.11781/sysydz201905621

Abstract(1517) PDF-CN(217)

Abstract:
There are various reasons for subeconomic wells in oil and gas exploration, including the problems of geology, engineering and management, among which the most common problem is geology. The lack of oil and gas accumulation in the lost well H drilled for natural gas in the Dengying Formation (pre-Cambrian) in the western Sichuan Basin was considered using geochemical tools, which include the optical analysis of bitumen and homogenization temperatures and gas compositions of fluid inclusions in dolomites filled in the dissolved fractures and pores. Oil accumulation in the well H area was normal from the Middle Triassic to the Early Jurassic. Bitumen was oxidized and washed by flowing waters in the period of oil cracking to gas from the Middle Jurassic to Cretaceous. As a result, there was no natural gas accumulation in the well H anticlinal area since the anticline was tilted and cut by a fault. The well H anticline was restored again during neotectonics in the Cenozoic, but there was no gas charging in the anticline because no gas was generated from oil-cracking or source rocks. Therefore, the well H was dry. Structures or traps with normal oil charging and normal gas charging and neotectonic stability are potential targets for gas exploration in the Dengying Formation in the Sichuan Basin.

Oil and gas exploration domains on the southern slope of Central Tarim Uplift, Tarim Basin

QIAO Guilin, ZHAO Yongqiang, SHA Xuguang, ZHOU Yushuang, LUO Yu

2019, 41(5): 630-637. doi: 10.11781/sysydz201905630

Abstract(1321) PDF-CN(132)

Abstract:
Based on the analysis of seismic facies characteristics, combined with the relationship between sedimentary facies and TOC content of the main wells, we suggested that the sedimentary facies of the Middle-Lower Cambrian on the southern slope of Central Tarim Uplift is the same as those of the Central Tarim Uplift. The main deposits there are the evaporative platform in salt (mud) and the restricted dolomite platform facies. The hydrocarbon generation potential in the study area is worse than that of the dark grey and black mudstone (shale) developed in a deep water and under-compensated environment on the Manjiaer Slope. Also, we analyzed the accumulation characteristics of the main oil and gas reservoirs, and the reasons why nearly 20 wells in the buried hill area on the southern slope failed to produce commercial oil or gas. It was pointed out that faults controlled storage, reservoir and enrichment. The Ordovician oil and gas enrichment areas in the Central Tarim Uplift are mainly the intersection of the NW and NE fractures, the Central Tarim no. I "Y" type fault zone, the vicinity of NE strike-slip faults (< 1 km), the oil source communicating faults with a big fault throw (T₈¹), and the graben-tensional fracture zone of NE strike-slips. It was pointed out that exploration of buried hills on the southern slope of Central Tarim should change from the high trap position of buried hills to the high trap position of dolomite buried hills near the main fault. The high positions of large anticlinal structural traps close to oil source with source communicating fractures and favorable reservoir and cap assemblage are the pre-salt hydrocarbon enrichment areas in Cambrian.

Evaluation of shale gas potential in Ordovician Wufeng-Silurian Longmaxi formations, Mugan syncline, northeastern Yunnan

YANG Ping, WANG Zhengjiang, YU Qian, LIU Wei, XIONG Guoqing, LIU Jiahong, HE Jianglin

2019, 41(5): 638-647. doi: 10.11781/sysydz201905638

Abstract(1060) PDF-CN(123)

Abstract:
Shale gas potential was evaluated according to wells Xd2 and Ydd3 in the Ordovician Wufeng-Silurian Longmaxi formations in the Mugan syncline of the northeastern Yunnan, using core test results, data from the neighboring area, black shale lithology, distribution, organic geochemistry, reservoir and gas bearing characteristics. The Wufeng Formation to the first member of Longmaxi Formation is mainly composed of deep-water shelf black carbonaceous shale and silty mudstones. The first member of Longmaxi Formation can be divided into the 1st, 2nd and 3rd submembers. The high-quality shale section with a total organic carbon content greater than 2.0% is 40-70 m thick, and the average organic carbon content is 3.00%-3.61%. The kerogen carbon isotope is -30.21‰ to -27.01‰. The higher the organic matter content, the better organic matter type is. The equivalent vitrinite reflectance (VR_o) is 2.73%-2.79%. The shale has limited quartz and feldspar, but more carbonate and pyrite. From bottom to top, quartz, carbonate and pyrite contents decrease, while feldspar and clay contents increase. The shale porosity is 2.38%-8.53%, and the transverse permeability is (0.000 01-15.0)×10^-3 μm², indicating medium porosity and low to extra low permeability. Mesopores and micropores formed by organic matter evolution are dominant. The Wufeng-Longmaxi shale is 1 500-2 300 m deep in the Mugan syncline. The gas-bearing area is 125.55 km², and the resource is 100×10⁹ m³. The main gas-bearing interval is located in the upper member of Wufeng Formation to the first member of Longmaxi Formation, with a thickness of 38-43 m and an average total gas content of 2.95-4.31 m³/t. The Wufeng-Longmaxi shale in the Mugan syncline has a large thickness, a continuous distribution in the horizontal and vertical directions, and a moderate burial depth, which show a great resource potential.

Marine oil and gas accumulation in Yakela area, northern Tarim Basin

HAN Qiang, HUANG Taizhu, GENG Feng, FEI Jianwei, YANG Xiyan

2019, 41(5): 648-656. doi: 10.11781/sysydz201905648

Abstract(1327) PDF-CN(138)

Abstract:
The filling and accumulation process of marine oil and gas was studied using oil and gas geochemistry, fluid inclusions and tectonic evolution in Yakela area of northern Tarim Basin. Marine hydrocarbon accumulation took place in Yakela area in two stages:the early (45.5-16.5 Ma) and the middle-late (22-4 Ma) Himalayan, and was featured by multi-stage filling and late accumulation. The late filling and accumulation of marine oil and gas were controlled by the "structural tilting" in Yakela area in the late Himalayan. In the early Himalayan period, the pre-Mesozoic structure was higher in the northeast and lower in the southwest. The range of marine oil and gas filling was wide, and the Yakela and eastern Yakela tectonic traps were favorable in the early Himalayan. In the late Himalayan, the Mesozoic tectonics in Yakela area warped and tilted due to the rapid subsidence of Kuqa Depression. The pre-Mesozoic structure became higher in the southwest and lower in the northeast. The Luntai fault belt and its southern traps are favorable for marine oil and gas filling in the late stage. Meanwhile, the earlier oil and gas reservoirs were damaged or adjusted southwards due to tilting.

Fracture characteristics and controls on reservoirs in Fulongquan Fault Depression, Songliao Basin

GUO Xinjun

2019, 41(5): 657-662. doi: 10.11781/sysydz201905657

Abstract(926) PDF-CN(119)

Abstract:
The horizontal and vertical characteristics of nearly 30 faults in the Fulongquan Fault Depression in the southeastern uplift of the Songliao Basin were analyzed. According to the epochs and controls of these faults, we classified them into three stages and three levels. The level 1 includes depression controlling faults, the level 2 includes synsedimentary faults, and the level 3 includes accommodation faults. On the western slope of the Fulongquan Fault Depression, there mainly develop level 2 and level 3 faults. Meanwhile, based on the hydrocarbon shows revealed by wells on both sides of the fault F6 on the western gentle slope, we analyzed the conducting and sealing effects of faults on hydrocarbon. A large number of induced fractures were developed on the active side of faults. Mudstones on the passive side laterally block oil and gas. It confirms that the active side of faults is favorable for hydrocarbon migration, while the passive side is favorable for hydrocarbon sealing. Based on the difference between the combination of sedimentary and accommodation faults, we identified the controls of fractures on hydrocarbon accumulation in primary and secondary reservoirs on the western slope of Fulongquan Fault Depression.

Characteristics of mixed sediments and influence on reservoir of Lower Cambrian Longwangmiao Formation, northern Sichuan Basin

WANG Han, LI Zhiwu, LIU Shugen, SONG Jinmin, RAN Bo, YE Yuehao, HAN Yuyue, JIANG Xun

2019, 41(5): 663-673. doi: 10.11781/sysydz201905663

Abstract(1093) PDF-CN(139)

Abstract:
Through outcrop observation and thin section identification, the mixed sediments of the Lower Cambrian Longwangmiao Formation in the northern Sichuan Basin are divided into tidal flat facies margin Ⅰ type, intershoal sea facies margin Ⅱ type, shoal facies margin Ⅲ type, open marine punctuated Ⅰ type and open marine punctuated Ⅱ type. The tidal flat facies marginⅠ type with the strongest mixing effect is mainly distributed in the bottom, middle and top of the Longwangmiao Formation. Laterally, the facies mixing sedimentation mainly distributes in the inner ramp which is close to the provenance on the west side, while the punctuated mixing sedimentation mainly distributes in the middle-outer ramp which is far away from the provenance on the east side. The Longwangmiao Formation in northern Sichuan Basin is characterized by NW-SE direction ramp sedimentation under a mixed sedimentation background. The mixed sedimentation is not conducive for the formation of a granular beach. The strong mixed deposits weakened the cementation between grain dolomites, leading to poorer compaction resistance, which is unfavorable for the formation and preservation of primary pores. Meanwhile, quartz has better stability and is difficult to dissolve in an acidic environment, which reduces the reservoir improvement by organic acids during the middle and late diagenetic stages. Therefore, the Lower Cambrian Longwangmiao Formation in northern Sichuan Basin does not have a lot of advantages to form high quality reservoir which is dominated by shoal deposits with obvious dissolution.

Relationship between orogenic belt uplift and non-equilibrium subsidence basins: a case study of Chang 7 and Chang 6 oil reservoirs in Longdong area, Ordos Basin

CHEN Zhaobing, CHEN Xinjing, HUANG Jinxiu, SHI Yi, ZHU Yushuang, CAO Jiangjun, XIE Yuhang, RUAN Yu

2019, 41(5): 674-681. doi: 10.11781/sysydz201905674

Abstract(894) PDF-CN(122)

Abstract:
The influence the Qinling Orogenic Belt uplift on provenance to the Chang 7 and Chang 6 oil reservoirs in the Longdong area of the Ordos Basin was analyzed. Outcrop and core observation and zircon U-Pb dating were used to characterize the temporal and spatial distributions of deposits such as tuff interlayers, gravity flows and seismites. The relationship between orogenic belt uplift and deposits were discussed. The "scissor-like" subduction closure of the Qinling Orogenic Belt from east to west was the driving force for the continuous migration of the depositional center of the basin, and the largest deep depression was formed in the southwestern part of the lake basin during the Chang 7 period. The intrusive "S-type granite" associated with the uplift of the Western Qinling provided a material source for the deep depression area in the southwest. Deposits are widely distributed in the deep depression area, among which the tuff interlayer is homologous to the intrusive magmatic rocks of the West Qinling, and the thickness gradually decreases from south to north. Turbidity current and some sandy clastic flow deposits were developed in the southwestern slope break belt of the deep depression area, while sandy clastic flow and some turbidity flow and argillaceous clastic flow deposits developed in the northeastern part of the depression area. From the southwest to the northeast of the basin, the deformation frequency, magnitude and scale of seismic core gradually decreased, indicating that the source is from the vicinity of the West Qinling. Therefore, the uplift of the Qinling Orogenic Belt has a good spatio-temporal coupling relationship with the non-equilibrium settlement and sedimentary response characteristics of the Ordos Basin.

Sand body configuration and gas-bearing properties of near source sand-gravel braided river on the northern margin of Ordos Basin

QI Rong, LI Liang, QIN Xuefei

2019, 41(5): 682-690. doi: 10.11781/sysydz201905682

Abstract(1510) PDF-CN(121)

Abstract:
The first member of the Lower Permian Shihezi Formation in the Duguijiahan area of the Hangjinqi region on the northern margin of Ordos Basin was deposited on the southern slope of Gongkahan paleocontinent, forming a set of sand-gravel braided river deposits near the provenance area. The physical properties of sand bodies are well correlated with gas-bearing properties; however, the heterogeneity of channel sand bodies is very strong, resulting in great differences in gas-bearing properties. The sand body configuration of the sand-gravel braided river in the 1st member was analyzed. The lithofacies characteristics and main configuration units were clarified. Through core observation and logging data analysis, six typical lithofacies were classified in the 1st member, with channel bar and braided channel as the main configuration units. The channel bar generally has four lithofacies assemblages:Gm (gravel massive bedding)-Sgt (gravel-bearing sandstone trough cross bedding)-Sm (sandstone massive bedding), Gm-Sm-Sp (sandstone parallel bedding), Sgt-Sm and Sm-Sp. The braided channel generally has four lithofacies assemblages:Gm-Sp, Gm-St, Sgt-Sp and Sgt-St. This lithofacies changes are the main reason for the strong heterogeneity. The statistical data from vertical wells, horizontal wells and seismic data show that the length of the channel bar is 230-1 050 m. According to empirical formulas, the width of the channel bar is 43-386 m. The channel bar sand body and braided channel sand body are laterally symbiotic, but their physical properties and gas-bearing properties are obviously different. Statistical data show that the physical properties and gas-bearing properties of channel bar sand body are better than those of the braided channel sand body.

Characteristics of shale and main controlling factors of shale gas enrichment of Lower Cambrian Niutitang Formation in western Hubei

ZHANG Yanlin, DUAN Ke, LIU Zaoxue, JIN Chunshuang, CHEN Ke, LUO Fan

2019, 41(5): 691-698. doi: 10.11781/sysydz201905691

Abstract(1092) PDF-CN(144)

Abstract:
We conducted some detailed studies of shale characteristics, physical properties, mineral composition, pore structure and gas content, and further offered a preliminary discussion about the shale gas enrichment regularity of the Lower Cambrian Niutitang Formation in the western Hubei by combining outcrop and core descriptions, gas logging, seismic cross section, mineralogical analysis, organic geochemical analysis with site desorption data. The black shale of the Lower Cambrian Niutitang Formation in Yichang and Zigui area was deposited mainly on a deep water shelf. The average TOC content is~3.2% and the organic matter is over-mature. The samples are dominated by clay minerals with quartz the second. The greater the effective thickness and total thickness of the shale in a single layer, the better the gas-bearing capacity of the shale.

Sedimentary characteristics of Permian-Triassic in Yangkang area, South Qilian Basin

YAO Haifeng, WANG Jia, TAN Xianfeng, CHEN Lei, YANG Cheng, XIAO Long, LIU Shiming, JIANG Cong

2019, 41(5): 699-707. doi: 10.11781/sysydz201905699

Abstract(1051) PDF-CN(103)

Abstract:
The field geological profile measurement and the thin section identification of rocks were used, combined with stratigraphy, sedimentary petrology and petroliferous basin analyses, to study the rock assemblage types and sedimentary facies evolution of the Permian-Triassic in the Yangkang Uplift and its surrounding areas, the South Qilian Basin. The study area is mainly composed of three tectonic units:the Yangkang Uplift, the Halahu Depression and the Xiariha Depression. The Middle Permian to Upper Triassic strata were well developed and lithologically variable. The sediments include carbonate platform, shallow shelf, littoral, delta, fluvial and lacustrine facies. There are two distinct sedimentary cycles, corresponding to two large-scale transgressive and regressive deposits. The tectonic evolution of the study area is the key factor determining its sedimentary evolution. Since the Caledonian Movement, the Yangkang Uplift existed as a paleo-uplift, which controlled the whole Permian-Triassic sedimentary paleogeographic environment. The uplift has not received sediments since the Late Silurian, and only includes Permian-Triassic strata in the Halahu Depression and the Xiariha Depression.

Characteristics of hydrocarbon plays in faulted formations, Changling Fault Depression, southern Songliao Basin

LI Hao, WANG Baohua, LU Jianlin, ZUO Zongxin, XU Wen, LÜ Jianhong

2019, 41(5): 708-716. doi: 10.11781/sysydz201905708

Abstract(1126) PDF-CN(93)

Abstract:
The sedimentary fill of the Changling Fault Depression in the southern Songliao Basin has the dual characteristics of "volcano-sedimentation". There are many types of hydrocarbon plays with a low degree of exploration in the faulted formations of the Changling Fault Depression. The major plays are different from one structural zone to another. Starting from the classification of hydrocarbon plays and exploring the reasons for distribution differences, we analyzed the characteristics, distribution rules and main controlling factors of hydrocarbon accumulation in volcanic rocks and tight clastic rocks in the study area. Based on the above findings, we established three pool-forming patterns. (1) The near-source, near-crater subfacies, fault transport, regional caprock, and inherited paleo-uplift jointly controlled the oil and gas enrichment in the volcanic rocks in the Yingcheng Formation. (2) Direct caprock, unconformity-fracture composite transport, near-source, inherited slope zone (super-stripping zone) jointly controlled the hydrocarbon accumulation in the clastic rocks in the Yingcheng Formation. Advantageous facies belt, inverted tectonic belt/slope break zone, burial depth, reasonable arrangement of sand body and oil source fault and regional caprock jointly controlled self-generated and self-storing tight oil and gas enrichment in the Shahezi Formation. Based on the analysis of the main controlling factors of hydrocarbon accumulation, the key parameters and standards of oil and gas evaluation for different types of hydrocarbon plays were proposed. It was pointed out that the volcanic rock plays of the Yingcheng Formation in the Chaganhua area, the tight clastic rock plays of the Yingcheng and Shahezi formations in the Longfengshan, Dongling and Fulongquan area are the key exploration directions.

Identification of a Triassic anomaly in deep water of Northern Carnarvon Basin, Australia

XU Xiaoming, YANG Songling, YIN Chuan, YAN Qinghua, TAN Zhuo

2019, 41(5): 717-723. doi: 10.11781/sysydz201905717

Abstract(825) PDF-CN(91)

Abstract:
The deep-water area of the Beagle Depression in the Northern Carnarvon Basin is at an early exploration stage. Cygnet anomaly, which was found in Triassic strata, has not only the paleotectonic background of developing carbonate reefs, but also the possibility of being volcanic rocks. In order to distinguish whether the Cygnet anomaly is volcanic rock or reef, a set of four-step analytical techniques was applied in this area. (1) Seismic facies analysis. Based on the interpretation of 3D seismic data, comprehensive seismic attributes as well as seismic facies, the shape of the Cygnet anomaly was identified. (2) Inner structure analysis. The inner structure of the Cygnet anomaly was dissected by using waveform clustering and 3D visualization techniques. (3) Gravity and magnetic analysis. The gravity and magnetic properties of the Cygnet anomaly were identified by carrying out gravity and magnetic seismic inversions. (4) Regional volcanic activity analysis. Combined the restoration of paleo-structure, the analysis of lithofacies paleogeography and the investigation of regional volcanic activity, the volcanic activity period and time were confirmed. Finally, it was concluded that the probability that the Cygnet anomaly is igneous rock was high, and some important seismic facies such as volcanic channel facies, volcanic intrusive facies, overflow facies and pyroclastic sedimentary facies were identified. This set of anomalous body identification technology in a pre-drilling deep-water area has a good application. It can identify anomalous body characteristics in the early exploration stage and optimize drilling investment.

Stratigraphic division and geochemical characteristics of freshwater lacustrine shale: a case study of Jurassic Da'anzhai Section, Sichuan Basin

WANG Wei, HUANG Dong, YI Haiyong, ZHAO Rongrong, CEN Yongjing, LI Yucong

2019, 41(5): 724-730. doi: 10.11781/sysydz201905724

Abstract(1140) PDF-CN(135)

Abstract:
The fine division and resource potential evaluation of lacustrine shale in the Da'anzhai Section of the Jurassic Ziliujing Formation in the Sichuan Basin were made based on lithologic, electrical, cyclic characteristic and shale geochemical data. The Da'anzhai Section was divided into three sub-sections, Da 1, Da 1 3 and Da 3, from top to bottom. The Da 1 3 sub-section was further divided into three sub-layers, Da 1 3 a, Da 1 3 b and Da 1 3 c, from top to bottom. The Da 1 3 c sub-layer mainly developed shore-shallow lake block shale, with large lateral changes. The organic matter is mainly the humic type Ⅱ₂ kerogen. The average organic carbon content is about 1%, and the average Rock-Eval S₁ content is 0.8 mg HC/g rock. The Da 1 3 b sub-layer mainly developed semi-deep lacustrine shale with thin layers of dielectric limestone, showing a stable thickness. The organic matter is mainly type II₁ kerogen with partial gel type. The average organic carbon content is more than 1.5%, and the average S₁ content is 1.18 mg/g. The Da 1 3 a sub-layer mainly developed shallow lacustrine shale with normal and thin dielectric limestone. The organic matter is mainly type II₂ kerogen with partial gel type. The average organic carbon content is 1% to 1.5%, and the average S₁ content is 1.21 mg/g. Based on current geological characteristics, funds, technical conditions and exploration results, it was proposed to open up a pilot test area of lacustrine shale oil and gas in the Gongshan Temple area in central and northern Sichuan Province, and concentrate on the Da 1 3 a and Da 1 3 b sub-layers.

Pyrolysis hydrocarbon generation of the main source rock in Yin'gen-E'ji'naqi Basin

ZHU Lianfeng

2019, 41(5): 731-738. doi: 10.11781/sysydz201905731

Abstract(1020) PDF-CN(110)

Abstract:
Lacustrine source rocks are widely developed in the second member of Bayingebi Formation of the Lower Cretaceous (K₁b²) in the Yin'gen-E'ji'naqi Basin, and they are the main petroleum source rocks in the basin. Pyrolysis experiments show that the total hydrocarbon yield of the samples is 265-798 mg/g, the oil yield is 264-779 mg/g in the "oil window" (EasyR_o of 0.7%-1.5%), and the yield of gaseous hydrocarbon during the main gas generation stage (EasyR_o>1.5%) is 191-583 mL/g, which indicates that the source rocks not only have a high oil generation potential, but also have a high gas potential. The variation of hydrocarbon products during the pyrolysis experiments allow the thermal evolution of organic matter of source rocks to be divided into four main stages. The first stage is kerogen pyrolysis and oil generation stage, with an EasyR_o of 0.57%-0.8% (the initial EasyR_o of pyrolysis experiment is 0.57%). Kerogen pyrolyzes into oil. The second stage is the condensate oil generation stage, with an EasyR_o of 0.8%-1.5%. Early oil cracks into light hydrocarbons and kerogen cracks into gas. In the third stage, oil cracks into gas, with an EasyR_o of 1.5%-3.3%. The fourth stage is the gas cracking stage, with an EasyR_o more than 3.3%. C_2-5 cracks into methane.

Preservation of crude oil with different properties and implication for deep oil exploration

WANG Qiang, NING Chuanxiang, MA Zhongliang, ZHENG Lunju, ZHUANG Xinbing, LI Fengxun

2019, 41(5): 739-745. doi: 10.11781/sysydz201905739

Abstract(1044) PDF-CN(109)

Abstract:
An evaluation of deep crude oil preservation ability identifies the depth limit of crude oil exploration. Thermal simulation products of crude oils with different properties and limestone media were analyzed and combined with oil cracking theory to develop an oil preservation index (OPI). The simulated temperature/thermal evolution degree is the key factor affecting crude oil preservation. OPI decreased by 0.230, 0.324 and 0.350, respectively, with VR_o increasing from <1.2%, 1.2%-2.0% to >2.0%. Crude oil with different properties often shows different preservation ability. Light oil, rich in saturated hydrocarbons with fewer branched chains and higher H/C atom ratio, shows stronger preservation ability in the early stage. But once the cracking threshold is reached, rapid cracking occurs. Heavy oil has more branched chains and heteroatoms due to the presence of non-hydrocarbons and asphaltene undergoes faster cracking in the early stage, and shows higher stability in the later stage. But most of the residue is solid bitumen and other macromolecule condensates. The depth limit of crude oil preservation was predicted by using the experimental results of thermal simulation in Manxi region, Tarim Basin. The depth limit of crude oil exploration in the southern Manxi region is 8 200 m.

Characterization of thin deltaic sand bodies of Carboniferous Karashayi Formation in Tahe Oil Field

ZHANG Fushun, QU Chang

2019, 41(5): 746-751. doi: 10.11781/sysydz201905746

Abstract(921) PDF-CN(97)

Abstract:
The Carboniferous Karashayi Formation in the Tahe Oil Field has a large burial depth, thin sand body thickness and fast lateral changes. Conventional wave impedance cannot easily distinguish sand and mudstone, and it is difficult to characterize sand bodies, which restricts the exploration and development in this area. Under the constraints of a sand body geological model, the combination of seismic waveform inversion and stratigraphic slice analysis was used to describe the sand bodies. The seismic waveform inversion technology can improve the vertical and horizontal identification accuracy of sand bodies synchronously, and realize the prediction of thin sand layers more than 3 m thick in the Karashayi Formation of the study area. The inversion results are highly matched with wells, and the post-test well-matching rate is 88.1%, which effectively improves the recognition ability of thin sand bodies. Stratigraphic slice analysis of the variation characteristics of the sand bodies in the target interval better reflect the sedimentary evolution of transgression and regression in the study area, and characterize the plane distribution of the thin sand bodies in the delta, providing a geological basis for finding favorable sand body development zones.

Identification and controlling factors of multi-scale lithofacies for continental shale under an isochronous stratigraphic framework: a case study in Dongying Sag, Bohai Bay Basin

CAO Bing, DU Xuebin, LU Yongchao, LIU Huimin, LIU Zhanhong, MA Yiquan, WANG Yong, ZHAO Ke, YANG Pan, PENG Li

2019, 41(5): 752-761. doi: 10.11781/sysydz201905752

Abstract(1062) PDF-CN(131)

Abstract:
At present, due to the diversity and complexity of terrestrial shales, it is difficult to identify and predict the shale facies precisely. At the same time, the controlling factors for shale development are not well understood. The study of shale facies and controlling factors in the Dongying Sag has allowed the identification of features of multi-scale lithofacies in lacustrine shale of different grades, and further identified two controlling factors. Lithofacies can be divided into layer coupling, layer coupling group, lithofacies domain and lithofacies sequence. The layer coupling is controlled jointly by paleoproductivity, monsoon and oxidation-reduction, while the layer coupling group-lithofacies domain-lithofacies sequence are controlled jointly by material source, climate and structure, thus resulting in the complexity and diversity of continental shale lithofacies. The results can be used to systematically understand the multi-scale characterization and research of lacustrine shale lithofacies.

Genetic mechanism and quantitative evaluation of fault traps in Xicaogu structural belt, Shulu Sag, Bohai Bay Basin

XIAO Yao, LI Xiaodong, ZHENG Ronghua, LIU Cong, ZHAO Zhengquan

2019, 41(5): 762-768. doi: 10.11781/sysydz201905762

Abstract(784) PDF-CN(106)

Abstract:
The fault traps in the Xicaogu structural belt in the Shulu Sag of the Bohai Bay Basin were studied. They are mainly synthetic fault traps and antithetic fault traps. A displacement-distance curve was drawn according to the variation of displacement. In this way, the segmental growth process of faults was restored, and the genetic mechanism of faults was determined. The synthetic fault traps were developed at the segmental growth point of the hanging wall of the fault. The antithetic fault traps were developed between the segmental growth points of the head wall of the fault during fault nucleation, with the largest displacement in the head wall of the fault. Some parameters such as the correlation between faults and strata (synthetic or antithetic faults), the maximum displacement, fault dip angle and strike, stratigraphic dip angle, fault segment length and formation rotation angle were selected to quantitatively evaluate their controls on fault physical properties. A model and a quantitative calculation method for the area of synthetic and antithetic fault traps were established, and were applied in the Jin 93 fault trap. The calculated error value is only about 2%, which indicates that the quantitative evaluation of fault traps is feasible.

Experimental study on fracture contribution to gas reservoir permeability and well capacity

MEI Dan, HU Yong, WANG Qian

2019, 41(5): 769-772. doi: 10.11781/sysydz201905769

Abstract(920) PDF-CN(111)

Abstract:
Fractures are an important channel for the seepage of reservoir gas. It has an evident contribution to reservoir permeability. However, it is currently difficult to quantitatively evaluate. To solve this problem, an experimental test of gas permeability was carried out after the artificial quantitative fracturing of core. Three factors such as fracture penetration degree, fracture length and width were considered. The contribution of fractures to rock permeability was investigated under two conditions, one where fractures completely penetrate through the rock matrix, and the other in which fractures incompletely penetrate through the rock matrix with penetration degrees of 20%, 40%, 60% and 80%. Both types of fractures contribute to rock permeability. The penetrating fractures increase rock permeability by more than 80%, which is closely related to fracture opening degree (length×width). The nonpenetrating fractures also contribute to rock permeability, by communicating with the matrix and improving reservoir flow. Based on experimental tests, a mathematical model of fracture contribution to single gas well production capacity was established combining three factors:fracture conductivity, fracture communication and matrix gas supply capacity. The fracture contribution to gas well production capacity was estimated using this model together with the basic parameters of actual gas wells.

A method for predicting production capacity based on a shale gas content test

JIANG Zhigao, CAO Haihong, DING Anxu, GAO Hequn

2019, 41(5): 773-778. doi: 10.11781/sysydz201905773

Abstract(757) PDF-CN(104)

Abstract:
At present, there is no way to predict shale gas well production capacity at home and abroad. There are many disputes because the gas content test results are different from later production. Through the analysis of the desorption process, the question as to why the output of many shale gas wells with similar gas volume is greatly different was preliminarily answered. Gas content data is not enough to characterize gas-bearing capacity, which should be taken into consideration together with the desorption process, such as desorption rate and free gas content factors. A new coefficient was defined, namely the gas content index:gas content index=desorption rate×free gas content×total gas volume. The internal meaning of the gas content index was also analyzed. Some relevant factors of shale gas production were screened through field gas content tests. Two factors, gas content index and pressure coefficient, which have an obvious correlation with daily production, were selected. A multiple regression model was established in view of these two factors. A daily output prediction formula was obtained. Daily output=0.146 7×pressure coefficient^7.2×gas content index+0.086 4. The reliability of the model was verified on site, so that the capacity of shale gas wells can be preliminarily predicted after the completion of field gas content testing.

2019, 41(5): 779-779.

Abstract(476) PDF-CN(96)

Abstract:

2019 Vol. 41, No. 5

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