Xinjiang Petroleum Geology Founded in 1980, is sponsored by Xinjiang Petroleum Society, and jointly sponsored by Xinjiang Oilfield Company, Tarim Oilfield Company, Tuha Oilfield Company of PetroChina and Northwest Oilfield Company of Sinopec. The journal has extensive communications and exchanges with petroleum industry-related universities, colleges, research institutes, other journals and publishers in China. Xinjiang Petroleum Geology has many columns such as Oil and Gas Exploration, Reservoir Engineering, Application of Technology, Discussions...
01 October 2020, Volume 41 Issue 5 Previous Issue   
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Exploration History and Enlightenment in Junggar Basin
CHEN Lei, YANG Yiting, WANG Fei, LU Hui, ZHANG Yidan, WANG Xin, LI Yanping, LI Chen
2020, 41 (5):  505-518.  doi: 10.7657/XJPG20200501
Abstract ( 67 )   HTML ( 4 )   PDF (5958KB) ( 82 )  

To write the book of Petroleum Geology of China, first we summarize the petroleum geological theory, exploration targets and results, review the exploration history and analyze the drilling, seismic, reserves and other historical data, then divide the exploration history of the Junggar basin into five stages — surface geological survey and drilling in the southern margin (before 1954), discovery and expansion of Karamay oilfield (1955-1977), strategic development of eastern oil and gas fields (1978-1989), fast breakthrough to desert oil and gas fields in the hinterland (1990-2002) and large-scale development of hydrocarbon-rich sags (2003-), and finally based on the important exploration results and milestone data of all stages, point out the exploration enlightenment and accumulation models that have important influences on exploration, including structural oil-bearing model in overthrust fault zones, large-area above-source and fan-controlled accumulation model in sags, stepped outer-source, along ridge and fault-controlled accumulation model, inner-source self-generation and self-preservation accumulation model of volcanic rocks, and accumulation models with upper, middle and lower assemblages in the southern margin. These findings are expected to have important enlightenment for future exploration.

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Reservoir-Forming Conditions and Exploration Practices of Wutonggou Formation in Western Dinan Swell, Junggar Basin
WANG Gang, SHI Xinpu, LIU Xuemei, LIU Yunhong, ZHU Zhonghua, HOU Lei
2020, 41 (5):  519-526.  doi: 10.7657/XJPG20200502
Abstract ( 32 )   HTML ( 4 )   PDF (2587KB) ( 37 )  

Superior conditions in the Dinan swell help develop three sets of hydrocarbon source rocks including Paleozoic Carboniferous Dishuiquan formation, Songkaersu formation and Permian Pingdiquan formation, which have good hydrocarbon supply capacity. Comprehensive analysis of accumulation conditions, seismic reservoir prediction and regional geology shows that large near-source oil and gas reservoirs could be developed in the Permian Wutonggou formation. This is the first set of sedimentary reservoir-cap assemblage above the unconformity in the Carboniferous top, whose transport system is composed of late Hercynian faults and the unconformity in the Carboniferous top, and the regional caprock composed of the upper 100-meter-thick mudstone is developed in the high-stand system tract. In the western section of the swell, transgressive sand bodies are constructive delta deposits, with the characteristics of superimposed and continuous accumulation. In the swell slope and sag areas, large and thick sand bodies of low-stand system tract are developed, but with poor physical properties. Sedimentary bodies with good physical properties such as slope deposits or alluvial fans and mid-fans can form massive oil and gas reservoirs with low porosity, low permeability and low abundance. The potential around the gas reservoirs that have been discovered in the Wutonggou formation is still large, and new gas reservoirs may be discovered in the slope and sag areas.

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Ordovician Karst Paleogeomorphology During Early Hercynian Movement in Tahe Oilfield
ZHANG San, JIN Qiang, ZHAO Shenzhen, SUN Jianfang, LI Yongqiang, ZHANG Xudong, CHENG Fuqi
2020, 41 (5):  527-534.  doi: 10.7657/XJPG20200503
Abstract ( 34 )   HTML ( 4 )   PDF (3782KB) ( 39 )  

Using a large amount of geological and geophysical data, the genetic process of the Ordovician karst paleogeomorphology during the Early Hercynian movement in the Tahe oilfield was investigated from the point of tectonic deformation by means of logging-seismic combination, stratigraphic interpretation and 3D modeling. The results show that there are two Paleozoic intervals with distinct deformation. The upper is a Cambrian-Ordovician carbonate formation showing as a gentle anticline, and the lower is a Carboniferous-Permian clastic formation showing as a fold chain overlying the Ordovician. The “impression method” isn’t suitable for the restoration of the paleokarst landform in the study area. Instead, we built a structural equivalent arc curve equation based on the present Ordovician top structural geomorphology, and used the equal arc length integral method to effectively remove the structural deformation after the karst period and restored the paleogeomorphology according to the compression ratio of different structural stages. The karst paleogeomorphology during the Early Hercynian movement was high in the north and low in the south, plunging to the west and rising to the east. The structure relief was 70% of the present one, showing a successive development feature. The complete and independent karst system is composed of two high and steep banded hoodoos-uplands, a lower karst depressions with a dustpan shape and a flat and open karst lake in the south of study area.

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Seismic Prediction Methods of Shale Oil Sweet Spots in Lucaogou Formation of Jimsar Sag
JIA Shuguang, WANG Jun, WANG Lingling, YU Hongguo, QI Jie, ZENG Tan
2020, 41 (5):  535-541.  doi: 10.7657/XJPG20200504
Abstract ( 37 )   HTML ( 5 )   PDF (3338KB) ( 27 )  

It is difficult to predict the tight dolomite reservoirs in the Lucaogou formation in the Jimsar sag of the Junggar basin using conventional seismic inversion methods because of the poor physical properties, strong heterogeneity and small impedance contrast between the sweet spot reservoirs and surrounding rock. We begin with rock physics to analyze the seismic response characteristics of the tight reservoirs and search for sensitive parameters of inversion, then carry out poststack and prestack inversion to detect shale sweet spots, and finally select the most suitable methods according to the actual drilling results, and develop comprehensive technologies for predicting shale oil sweet spots. The study indicates: 1. The crossplot of P-wave velocity and density after coordination rotation can be used to identify ClassⅠ reservoirs in the upper sweet spot interval in the Lucaogou formation; 2. The crossplot of P-wave impedance and S-wave impedance can distinguish ClassⅠ, ⅡfromⅢ reservoirs and non-reservoir zones in the lower sweet spot interval in the Lucaogou formation; 3. NMR porosity is the best parameter for shale oil identification, whose lower limit is 4%; and 4. The comparison of the identification results from poststack RMS amplitude, poststack absorption attenuation, prestack AVO and prestack synchronous inversion methods, and formation test data indicates that prestack synchronous inversion is more advantageous in sweet spot prediction in the study area, and based on which, 3 types of reservoirs are classified.

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Distribution and Genesis of Abnormal Bodies in Maokouzu Sag in Kaijiang Area, Northeastern Sichuan Basin
YANG Liu, ZANG Dianguang, XU Baoliang, DENG Shaoqiang, CHEN Hongfan, YANG Rongrong, CHEN Wei
2020, 41 (5):  542-549.  doi: 10.7657/XJPG20200505
Abstract ( 21 )   HTML ( 2 )   PDF (9335KB) ( 20 )  

Based on 3D seismic data and high-precision seismic curvature, the distribution and genesis of the abnormal bodies on seismic sections are analyzed in the Maokouzu sag in the Kaijiang area, northeastern Sichuan basin. It is found that the abnormal bodies are widely distributed in the Kaijiang area and mainly located near the NWW-SEE strike-slip faults developed during the Emei taphrogenesis. The strike-slip faults provide good channels for the migration of hydrothermal fluid which erodes the limestone of the Maokou formation, and consequently creates good reservoirs. Joint analysis of seismic and geological data found that it was hydrothermal dissolution that caused the formation of abnormal bodies in the Maokouzu sag. It is of great significance to make clear the distribution and genesis of the abnormal bodies in expanding the exploration field and increasing the reserves and production in the northeastern Sichuan basin.

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Pore Characteristics of Marine Shale in Lower Cambrian Hetang Formation in Xiuwu Basin
GUO Chunli, YANG Shuang, WANG Andong, ZHANG Shuanglong, QI Xing
2020, 41 (5):  550-556.  doi: 10.7657/XJPG20200506
Abstract ( 20 )   HTML ( 4 )   PDF (606KB) ( 20 )  

Based on porosity and low temperature N2 and CO2 adsorption experiments, the pore characteristics of the shale in the Lower Cambrian Hetang formation were quantitatively characterized. And combined with TOC, whole rock X-ray diffraction and previous research on the thermal evolution of organic matter, the controlling factors on the pore characteristics were discussed and analyzed. The results show that most pores are wedge-shaped, and less are like bottle-neck and slits. The porosity of the shale ranges from 1.24% to 2.91%, of which mesopores, micropore and macropore account for 44.53%, 35.45% and 20.01%, respectively. The total pore volume of the shale ranges from 5.33× 10-3 cm3/g to 20.10×10-3 cm3/g, of which the average pore volumes of BJH and DFT are 7.40×10-3 cm3/g and 2.24×10-3 cm3/g, respectively. The total specific surface area is 7.62 to 17.84 m2/g, of which the average specific surface areas of low-temperature N2 adsorption and CO2 adsorption are 5.23 m2/g and 7.41 m2/g, respectively. The peak pore size is less than 10.00 nm, and the micropore structures are complex. The pores of 0.30-0.70 nm are relatively developed, but the larger specific surface area provides more room adsorbing shale gas. TOC is the controlling factor on micropore development, and it is helpful to the development of mesopores, but influences less on macropores. Clay minerals reduce the shale porosity, while quartz is a favorable factor on the total pore volume and total specific surface area. With the similar characteristics to the Lower Jurassic Ziliujing formation shale in the western Hubei province, the marine shale of the Lower Cambrian Hetang formation in Xiuwu basin has a good reservoir capability.

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Lower Limits of Physical Properties of Sandstone Reservoirs in the Second Member of Sangonghe Formation in Moxizhuang Oilfield
2020, 41 (5):  557-564.  doi: 10.7657/XJPG20200507
Abstract ( 21 )   HTML ( 1 )   PDF (748KB) ( 18 )  

The second member of Sangonghe formation in Moxizhuang oilfield presents the characteristics of low porosity, low permeability and strong heterogeneity. Based on the data of conventional core analysis, mercury injection and formation test, the paper compares the application effects of commonly-used methods to determine the lower limits of physical properties of effective reservoirs in the study area, determines the lower limits of reservoir physical properties in the second member of Sangonghe formation, and analyzes the main factors influencing the lower limits of reservoir physical properties. The results show that the second member of Sangonghe formation in Moxizhuang oilfield is mainly composed of medium-fine sandstone deposited in delta front, the reservoir space of the formation is dominated by primary intergranular pores, and the methods of starting pressure gradient, the distribution function curve and oil-bearing occurrence are very practical for determining the lower limits of reservoir physical properties in the study area, and the lower limits of reservoir porosity and permeability are determined as 10.1% and 1.15 mD, respectively. Sedimentary facies and diagenesis are the main factors affecting the lower limits of reservoir physical properties. Strong dissolution, weak compaction and weak cementation reservoirs of underwater distributary channel microfacies have the lowest limits of physical properties. In addition, crude oil properties and reservoir burial depth are the minor factors affecting the lower limits of reservoir physical properties.

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Investigation on How Binary System Matches with Reservoir Permeability: A Case Study of the Conglomerate Reservoir in Lower Karamay Formation in District Qizhong, Karamay Oilfield
NIE Xiaobin, LI Zhihong, LUAN Huoxin, WEI Kai, ZHANG Liwei, WANG Jian
2020, 41 (5):  565-570.  doi: 10.7657/XJPG20200508
Abstract ( 16 )   HTML ( 1 )   PDF (675KB) ( 17 )  

The reservoir permeability obtained from mud log in District Qizhong of Karamay oilfield is mainly distributed between 28.8 and 300 mD. The permeability contrast is large and channeling is serious in partial zones. Pilot tests on binary flooding found some wells blocked and the production capability reduced greatly, so it was urgent to understand how the binary flooding system can well match with the reservoir properties. Binary flooding experiments were performed on cores with different permeabilities, and the results were evaluated in resistance coefficient, residual resistance coefficient and viscosity loss rate. It is concluded that the binary systems with low or medium to high molecular weight (10 - 50 mPa·s and 10 - 20 mPa·s, respectively) are applicable for the reservoirs with the permeability not more than 30.0 mD, and those with low to medium (10 - 50 mPa·s) and high molecular weight (10 - 35 mPa·s) are applicable for the reservoir with the permeability of 30.0 to 100.0 mD, and those with low to high molecular weight (10 - 50 mPa·s) for the reservoir with the permeability of 100.0 to 300.0 mD.

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Calculation and Application of Key Combustion Parameters for Developing Heavy Oil Reservoirs: A Case Study of Wellblock H1 in Karamay Oilfield
XI Changfeng, ZHAO Fang, GUAN Wenlong, GAO Chengguo, HUANG Jihong
2020, 41 (5):  571-574.  doi: 10.7657/XJPG20200509
Abstract ( 16 )   HTML ( 2 )   PDF (462KB) ( 13 )  

Taking the combustion test in Wellblock H1 as a case, and starting from the conservation of matter and energy, the equilibrium relationship of underground combustion parameters under high-temperature combustion conditions is deduced, then the heat distribution to crude oil, rock skeleton, secondary water and other matters is analyzed in the process of combustion, and finally the parameters such as combustion temperature, air consumption, and air-to-oil ratio are calculated. The results show that in the actual production process, the air consumption of the oil layers is about 350 to 400 m3/m3, and the underground combustion temperature is about 550 °C. Based on the results, the experimental data are updated, and in order to further improve the development effect of fireflooding, the wet combustion plan is calculated. When air consumption is 350 m3/m3, the wet combustion water-to-air ratio is 0.000 779 m3/m3, and the cold water injection is 49.9 m3/d.

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Experiments on Hydraulic Fracture Propagation in Tight Sandstones with Different Brittleness
YE Liang, LI Xianwen, MA Xinxing, LI Sihai, ZHAO Qianyun, GE Qiang
2020, 41 (5):  575-581.  doi: 10.7657/XJPG20200510
Abstract ( 12 )   HTML ( 2 )   PDF (2669KB) ( 16 )  

Rock brittleness is closely related to the effectiveness of fracturing treatment in tight reservoirs, but the influence of the brittleness of tight rock on fracture propagation is still unclear. In order to study how hydraulic fractures propagate in tight sandstones with different brittleness, fracturing experiments were conducted on three types of tight sandstone using a true tri-axial fracturing simulation system. The influences of rock brittleness, fracturing fluid and bedding on fracture propagation were analyzed. Experimental results show that Shan-1 tight sandstone has the strongest brittleness,followed by Chang-7 tight sandstone, and He-8 tight sandstone has the weakest brittleness. In the case with less beddings, the fracture induced by slick water extends more completely, and more fracture branches are created by liquid CO2 in the most brittle Shan-1 tight sandstone than the He-8 tight sandstone. In the case with more beddings, the fracture shapes induced by liquid CO2 in Chang-7 tight sandstone are more complex than those in the relatively homogeneous Shan-1 and He-8 tight sandstones. Compared with slickwater, the fractures induced by liquid CO2 is narrower. Liquid CO2 fracturing is more suitable for the most brittle Chang-7 tight sandstone reservoir with many beddings.

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Determination of GWC and Estimation of Gas Reserves of P4 Reservoir of Pinghu Formation in M Gasfield
2020, 41 (5):  582-586.  doi: 10.7657/XJPG20200511
Abstract ( 16 )   HTML ( 2 )   PDF (551KB) ( 18 )  

Constrained by operation cost in the process of offshore gas field development, it is a common case that only a few exploratory and development wells are drilled for evaluating new structures. This often leads to the situation that no well is drilled into the gas-water contact (GWC), and consequently some uncertainties in the estimation of static geological reserves, and obvious differences between dynamic and static geological reserves with the development going on and more production data collected. Based on mercury injection experiments on special cores, the relationship between water saturation and gas column height under formation conditions is established by using the capillary pressure J function, then the gas column height in the P4 reservoir of Pinghu formation in M gasfield is calculated, and finally the static geological reserves are estimated again. The results are basically consistent with the dynamic reserves calculated using the material balance method. In addition, the geological model of the gas field is updated according to the new understanding. The modelled BHP is well consistent with the measured BHP, indicating the good agreement between predicted and estimated geological reserves. The method proposed in the paper is applicable to some extent.

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Dynamic Distribution of Remaining Gas Content in Steep and Thick Coal Seams in Baiyanghe Mining Area of Fukang
WANG Hongli, ZHANG Suian, CHEN Dong, HUANG Hongxing, ZHAO Zengping
2020, 41 (5):  587-591.  doi: 10.7657/XJPG20200512
Abstract ( 15 )   HTML ( 2 )   PDF (1037KB) ( 17 )  

The coal seams in Baiyanghe mining area of Fukang in Junggar basin, Xinjiang, are thick and steep, and where the dynamic distribution of remaining coalbed methane (CBM) content is different from conventional horizontal coal seams. On the basis of numerical simulation, the models of fractured vertical wells, open-hole horizontal wells, and staged fractured horizontal wells were built in extremely steep and thick coal seams to find the dynamic distribution of remaining gas content in different well types. The results show that, at the beginning of production stage, the remaining gas content changes like a fan with the perforated hole as the fan axis; in the early-middle stage of production, affected by the gas-water differentiation, coalbed methane desorbed from deep coal seams migrates to shallow layers and causes the shallow reservoir pressure to increase, and it is adsorbed by the coal seams again and results in the increase of gas content in the shallow layers; in the middle of production stage, there is a balanced area between adsorption and desorption in shallow-middle coal seams; in the middle and late stages of production, after the gas desorbed from deep layers is produced, the coal seam pressure will reduce, and the methane in the middle and shallow layers begins to release; and finally in the late stage of production, there is a large amount of remaining gas in the deep seams.

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Quantitative Characterization of Reservoir Changes Before and After Fire Flooding in Heavy Oil Reservoirs: A Case Study of Well Gao 3-6-18 in Liaohe Oilfield
YAO Qian, HAN Denglin, WANG Chenchen, YANG Chengye, CHEN Qi
2020, 41 (5):  592-598.  doi: 10.7657/XJPG20200513
Abstract ( 10 )   HTML ( 1 )   PDF (568KB) ( 11 )  

Fire flooding is one of the techniques for enhancing oil recovery in heavy oil reservoirs after steam stimulation. Reservoir is the fundamental factor influencing the effect of fire flooding, while temperature is the main factor affecting the changes of reservoirs during fire flooding. Taking the Well Gao 3-6-18 in Liaohe oilfield as an example, based on the physical simulation experiments and the samples obtained from different fire flooding stages, the change mechanism of reservoirs before and after fire flooding was analyzed, and the corresponding reservoir change patterns were established. The study shows that the physical properties of the reservoir in the coking zone are poor. The precipitates of Fe(OH)3 and CaCO3 and asphaltene sediments make the pore throats blocked. The clayization of the feldspar, accompanied with the forming of a large amount of siliceous cements, destroying the intergranular pores and the intragranular dissolved pores and leading the reduction of porosity and permeability. The reservoirs in the combustion zone and burned zone have better physical properties, in which the decomposition of precipitates of Fe(OH)3 and CaCO3 and the cracking of asphaltene sediments can enlarge the pore throats, the sintering of clay minerals makes kaolinite transform into montmorillonite and illite, along with the transformation of montmorillonite to illite, resulting in the volume contraction of intergranular interstitial materials dominated by clay minerals, and finally cracks occur between the particles and the interstitial materials. With the increase of temperature, the cracks become wider, the pore throats become bigger and the connectivity becomes better, then the reservoir porosity and permeability increase as well.

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Reservoir Geological Modelling and Its Application of the First Member of Xishanyao Formation in Luliang Oilfield
FANG Xiuze, FAN Zhuguo, DANG Sisi, ZOU Wei
2020, 41 (5):  599-604.  doi: 10.7657/XJPG20200514
Abstract ( 20 )   HTML ( 3 )   PDF (11012KB) ( 7 )  

The first member of Xishanyao formation(J2x1) in Wellblock LU9 is a reservoir with bottom water, which is mainly controlled by structure and affected by lithology in local areas. The results of formation test, production test and development test have proved that the reservoir has liquid producing capability, the lateral water cut is very different and the vertical OWC is complicated. In order to determine favorable development areas, it is urgent to conduct a research on fine 3D geological modeling. Based on the data of core, well logging, formation and production test and using Petrel modeling software, a 3D fine geological model was established to determine the oil layers and the spatial distribution of reservoir parameters in the study area. And according to the prediction of the model, favorable reservoirs with good lithology and physical properties were selected to allocate development wells. The fine geological model has been confirmed consistent with the real data, which provides a reliable basis for reservoir development and well allocation.

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Carbonate Reservoir Identification Based on Pure P-Wave Data
ZHANG Yuanyin, SUN Zandong, YANG Haijun, HAN Jianfa, ZHANG Jingting
2020, 41 (5):  605-611.  doi: 10.7657/XJPG20200515
Abstract ( 11 )   HTML ( 3 )   PDF (3658KB) ( 38 )  

Regarding the characteristics of large burial depth and strong heterogeneity of the paleokarst carbonate reservoir in the Tarim basin, the pure P-wave data calculated from pre-stack inversion are introduced to replace the traditional full-stack seismic data so that the accuracy of wave impedance inversion and reservoir prediction can be improved. The numerical modeling results suggest that compared with the theoretical zero-offset data, the computed pure P-wave data have negligible errors, while the traditional full-stack data inevitably contain errors that might associated with different factors, i.e., wavelet, incidence angle range and reflection boundary. The field data comparison in the Wellblock ZG8, Tazhong area shows that when the dominant frequency of P-wave in target carbonate strata has been improved by 8 Hz, the fitting rate of reservoir prediction result with actual drilling result can be increased by 7.39%, which provides practical methods and corresponding standards for the reservoir prediction in the carbonate reservoirs in Tarim basin.

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A Method to Determine Waterflood Front Based on Production Performance Data
MA Li, ZHANG Jiaosheng, WANG Ruiheng, LI Desheng, DU Shouli
2020, 41 (5):  612-615.  doi: 10.7657/XJPG20200516
Abstract ( 15 )   HTML ( 1 )   PDF (457KB) ( 30 )  

In view of the problems encountered in the low permeability reservoirs in Changqing oilfield, such as tight lithology, poor water injection efficiency, low single well production and strong plane heterogeneity, which lead to uneven waterflood, the paper established a basic model on the basis of waterflooding theories in low permeability reservoirs, considered the interference of production wells, introduced the factors influencing production according to the potential superposition principle, and established an easy method to determine waterflood front in a well group. This method has been applied in infill drilling adjustment of a low permeability reservoir in Erdos basin and the production cases can prove the feasibility and reliability of the method.

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Application of 3D Geological Modeling in Horizontal Well Development of Tight Sandstone Oil Reservoirs: A Case Study of Block S in Ordos Basin
LIANG Weiwei, DANG Hailong, CUI Pengxing, WANG Xiaofeng, HOU Fenchi, ZHANG Tianlong
2020, 41 (5):  616-621.  doi: 10.7657/XJPG20200517
Abstract ( 13 )   HTML ( 8 )   PDF (4311KB) ( 16 )  

In order to effectively improve the accuracy and success rate of drilling horizontal wells in tight sandstone oil reservoir in the southern Ordos basin, 3D geological modeling technology involving the geological structure, lithofacies, reservoir properties and configuration and GR curve of the Chang 8 member was based to design horizontal well trajectories and make adjustment while drilling in the S block. The results show that reservoir configuration model and natural gamma model can effectively characterize the distribution law of the sandbody in the target zones, and quantitatively support the design of horizontal well trajectories. The horizontal trajectories could be adjusted in time with the help of LWD GR data, so the horizontal sections could be always kept through the reservoirs with good physical properties. Three horizontal wells have been completed successfully at a drill-in rate of 98.5% in reservoirs and 90.3% in pay zones, and the post-fracturing production is high after putting into production. 3D geological modeling can effectively support the design and adjustment of horizontal well trajectories. The experience is of referential significance for drilling horizontal wells and development of the tight oil reservoirs in the Ordos basin.

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Discussion on Shale Oil in Jimsar Sag, Junggar Basin
CAO Yuanting, PAN Xiaohui, LI Jing, ZOU Yang
2020, 41 (5):  622-630.  doi: 10.7657/XJPG20200518
Abstract ( 37 )   HTML ( 2 )   PDF (683KB) ( 40 )  

Two conclusions have been existent about the crude oil of the Lucaogou formation in the Jimsar sag, Junggar basin. One conclusion classifies the crude oil as tight oil, and the other as shale oil. According to two national standards - Geological Evaluation Method for Tight Oil and Geological Evaluation Method for Shale Oil, the classification of the crude oil in the Lucaogou formation is determined. The studies show that, based on the source-reservoir relationship and layer thickness statistics, the crude oil in the Lucaogou formation of the Jimsar sag is shale oil; based on the occurrence, source-reservoir relationship and oil accumulation model, the oil is determined as shale oil which accumulates between layers. In terms of the geochemical parameters of the source rock, the lithology and physical properties of the reservoir, the parameters of the oil reservoir, fracture development and brittleness, this study investigates how the characteristics of the shale oil in the Lucaogou formation are different from the typical shale oil at home and abroad. The results show that the shale oil in the Lucaogou formation is of low to middle maturity, but a large amount of hydrocarbons have been generated and expelled in the early stage; the reservoir has high porosity, but its permeability is obviously low; the oil saturation of the reservoir is high and the oil is characterized by high density, high viscosity, low gas-oil ratio and poor fluidity. Natural fractures in the reservoir are not developed, and the brittleness calculated with the rock mechanical method is poor.

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