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01 April 2019, Volume 40 Issue 2 Previous Issue    Next Issue

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A New Breakthrough in Exploration of Large Conglomerate Oil Province in Mahu Sag and Its Implications TANG Yong, GUO Wenjian, WANG Xiatian, BAO Haijuan, WU Haisheng 2019, 40 (2):  1-1.  doi: 10.7657/XJPG20190201 Abstract ( 388 )   PDF (300KB) ( 1459 )   Save There had been no significant breakthrough in petroleum exploration in Mahu sag of Junggar basin for about 20 years after the discoveries of Mabei oilfield in 1993 and Ma-6 area in 1994. An overall evaluation was conducted regarding the resources, reservoirs and stimulation potential in Mahu sag in the year of 2010. The results showed that the slope area in Mahu sag was the key strategic area for petroleum exploration. Then the exploration idea was changed from the exploration for structures in the fault zones around source to the exploration for lithological reservoirs in the major area within source. Since 2012 more and more discoveries have been achieved successively. Up to now, 6 large reservoir groups have been discovered and 2 large oil provinces have been proved in the south and north, respectively. The incremental OOIP is 12.4×108 t, among which the proved reserves is 5.2×108 t. The discovery of the large conglomerate oil province proves that hydrocarbon could accumulate in the above-source conglomerate reservoirs under the conditions of fracture connecting, and efficient development could be realized in low-permeability conglomerate reservoirs by using fine volume fracturing technology Related Articles | Metrics

Structural Characteristics and Petroleum Exploration in Sikeshu Sag, Southern Margin of Junggar Basin YANG Disheng1, XIAO Lixin1, YAN Guihua1, WEI Lingyun1, WANG Xin2, WANG Xinqiang1 2019, 40 (2):  1-1.  doi: 10.7657/XJPG20190202 Abstract ( 181 )   PDF (300KB) ( 137 )   Save Sikeshu sag is located in the intersection area of the northwestern and southern margins of Junggar basin. Because of the complex structural deformation, ascertaining traps in the area is vital for petroleum exploration. Based on 2D and 3D seismic geometry and kinematics analysis and combined with regional structural mapping, the research adopts the ideas and techniques of structural modeling to build a deformation model of "two periods of superimposition and double layered structure" for Sikeshu sag. It is considered that deep and shallow structural layers are developed in the sag by taking the Cretaceous Tugulu mudstone and the detachment layer of mudstone of Paleogene Anjihaihe formation as boundaries. The deep structural layer is mainly composed of Mesozoic NW-SE trending strike-slip faults and en echelon-like folds and the shallow structural layer is a Cenozoic detachmetn thrust structure. The two periods of structures superimposes vertically and exhibit a Mesozoic en echelon-like structural framework laterally. Based on the comprehensive research of oil and gas accumulation, a hydrocarbon accumulation model of vertical superimposition is proposed for Sikeshu sag. The reservoir in the shallow structural layer is influenced by fault connection and its distribution is controlled by Cenozoic faults; the deep structural layer is very near to hydrocarbon generation center in which structural traps formed early and late deformation was weak, which benefits long-term hydrocarbon migration. The commercial oil and gas flow with the daily production more than 1 000 tons obtained from the Well Gaotan-1 in Jan., 2019 can prove that the hydrocarbon accumulation conditions of Sikeshu sag is favorable Related Articles | Metrics

Genesis of High-Yield Oil and Gas in Well Gaotan-1 and Characteristics of Source Rocks in Sikeshu Sag, Junggar Basin JIN Jun1, WANG Feiyu2, REN Jiangling1, FENG Weiping3, MA Wanyun1, LI Sijia2 2019, 40 (2):  1-1.  doi: 10.7657/XJPG20190203 Abstract ( 177 )   PDF (300KB) ( 642 )   Save A great breakthrough was achieved in Cretaceous Qingshuihe formation of Sikeshu sag in the southern margin of Junggar basin in January, 2019, and more than one thousand tons of commercial oil and gas flow per day has been obtained from the Well Gaotan-1, which set a new record of well daily production in Junggar basin. Meanwhile, the great exploration potential in Sikeshu sag of Junggar basin has been proved. To accurately evaluate the resources in Sikeshu sag and provide a basis for exploration deployment, the paper systematically analyzes the hydrocarbon properties in the well and its surrounding exploration wells and the characteristics of Jurassic source rocks, and discusses the relationship between hydrocarbon generation and accumulation in the sag. The study shows that the gas-oil ratio（GOR）of the Cretaceous pay zone in the Well Gaotan-1 is 260~360 m3/m3, and the crude oil is light oil with low density and low viscosity. The carbon isotope ratio of the crude oil is -26.83‰ with Pr/Ph as high as 3.6, and the abundance of tricyclic terpane C19, C20 and C21 decrease gradually, indicating typical geochemical characteristics of coal-bearing source rocks. The natural gas in the Well Gaotan-1 is exinite-rich, humic-type wet gas with the methane content of 74.44%, the carbon isotope ratio of methane and ethane of -40.35‰ and -28.74‰, respectively. The above hydrocarbon characteristics indicate that the oil and gas in the Well Gaotan-1 mainly come from Jurassic source rocks with the organic phase of D/E. The systematic source rock analysis shows that the source rocks of D/E and F organic phases are developed in the Middle—Lower Jurassic strata in Sikeshu sag, and the sag center is in condensate oil—wet gas stage and has high hydrocarbon generating potential. It is considered that the Jurassic petroleum system in the study area has great exploration potential Related Articles | Metrics

Fluid Features and Reservoir Types in Well Gaotan-1 in Sikeshu Sag, Junggar Basin LIANG Baoxing1, ZHOU Wei1, LIU Yong1, ZHANG Zixin1, ZHANG Ke2, LIU Weizhou1 2019, 40 (2):  1-1.  doi: 10.7657/XJPG20190204 Abstract ( 191 )   PDF (300KB) ( 405 )   Save Hydrocarbon compositions of the separated gas and oil from the Well Gaotan-1 are analyzed by using gas chromatography. The features of the surface oil from the Well Gaotan-1 is studied and in-depth research is carried out for formation fluid physical properties with PVT experimental instrument. The results show that for the formation fluids in the Well Gaotan-1, the content of C1—C5 components reach 71.41%, the content of light hydrocarbons is relatively high, the content of heavy components is low, the wax content and freezing point are medium, the density and viscosity are low, indicating characteristics of volatile oil. The crude oil is single-phase liquid under the formation conditions, the formation pressure is abnormally high, the difference between formation pressure and saturated pressure is large, the formation has sufficient energy, the shrinkage rate of the formation oil is relatively high and the elastic energy is relatively strong. Combining with the PVT data of the formation fluid and using a triangle chart of three elements in reservoir fluid and reservoir identification parameters (φ1), the paper considers that the reservoir in the Well Gaotan-1 is a low-saturation volatile oil reservoir Related Articles | Metrics

A Method to Study Time Effectiveness of Fault-Sand Configuration Transporting Hydrocarbon and Its Application FU Guang1, PENG Wantao1, XU Yanbin2a, XU Jiachao2b, AO Damu2c 2019, 40 (2):  1-1.  doi: 10.7657/XJPG20190205 Abstract ( 137 )   PDF (300KB) ( 328 )   Save In order to study the distribution of hydrocarbon which was generated in the lower source rocks and accumulated in the upper reservoirs in the source-reservoir-caprock combinations of a petroliferous basin, aiming at the time effectiveness of fault-sand configuration transporting hydrocarbon currently, and based on the determination of fault transporting- and sand transporting- hydrocarbon time, the time of fault-sand configuration transporting hydrocarbon is determined. Then compared with the hydrocarbon expulsion peak time, the paper establishes a method to study the time effectiveness of fault-sand transporting hydrocarbon and applies the method in Ed2 and Ed3 reservoirs in the Laoyemiao structure of the Nanpu sag. The study results show that the fault-sand transporting hydrocarbon time of Ed2 and Ed3 reservoirs in the Laoyemiao structure should be the deposition period of the upper Minghuazhen formation, later than the first hydrocarbon expulsion peak (middle deposition period of Guantao formation) of the source rocks of Es3 and Es1, which was not conducive to the hydrocarbon migration in this first peak period. However, the period of fault-sand configuration transporting hydrocarbon was slightly later than the second hydrocarbon expulsion peak (late deposition period of the lower Minghuazhen formation) of the source rock of the Es3 and Es1 and a certain amount of hydrocarbon could be transported, which was good for hydrocarbon accumulation. The results are consistent with the distribution of the hydrocarbon discovered in Ed2 and Ed3, which shows that the method is feasible to be used in time effectiveness research of the fault-sand configuration transporting hydrocarbon Related Articles | Metrics

Sedimentary Characteristics and Their Controlling Factors of the Third Member of Shahejie Formation in Gubei Sag QIU Longwei1,2, DU Shuanghu1,2, DAI Li3, ZHANG Zaipeng3, SUN Chao4, XIN Ye4 2019, 40 (2):  1-1.  doi: 10.7657/XJPG20190206 Abstract ( 145 )   PDF (300KB) ( 476 )   Save As a typical double-faulted lacustrine basin, the Gubei sag is affected by the alternation of faults along the boundary. The internal structure of the lacustrine basin is unique, the source system is complex, and the deposition types are diverse. Therefore, the accurate evolution restoration of the sedimentary system is the key to guiding oil and gas exploration in this type of basin. In this paper, the core, thin section, logging and seismic data were comprehensively used to conduct a detailed study on the characteristics of the source and sedimentary facies distribution of the third member of Shahejie formation in Gubei sag. The results showed that the alternating activities of Changdi fault and Chengdong fault in the east and west sides of Gubei sag resulted in the geomorphic features of “one swell sandwiched by two sags” of the lake basin. The strong activity of Zhuangnan fault in the north caused the characteristic of “faulting in the north and overlapping in the south” in the eastern subsag. The interior of the lacustrine basin is mainly controlled by the provenances coming from the 4 directions of Chengdong, Changdi, Gudao and Gudong. Progradational fan delta and retrogradational subaqueous fan distributed on the Chengnan steep slope accumulated alternatively and vertically. Progradational fan deltas are distributed in the faulted belt of Changdi steep slope and deltas are distributed on the eastern and western gentle slopes of Gubei sag. The fan delta coming from Gudong swell extends from the southeast to the north in the sag. Generally, faults give a few impacts on the gentle slope where fan delta sediments are mainly found and controlled by lake level and ancient landform. The steep slope is mainly constrained by both fault activity and lake level, and is dominated by subaqueous fan, fan delta and slip turbidite fan Related Articles | Metrics

Forming Mechanism of Smectite Coating of the Sandstones in Xiagou Formation of Yinger Sag, Jiuquan Basin ZHOU Xiaofeng1, LI Jing2, YU Junmin1, LI Shuqin2, FU Guohui2, SHENG Silu2, XU Rui2 2019, 40 (2):  1-1.  doi: 10.7657/XJPG20190207 Abstract ( 189 )   PDF (300KB) ( 460 )   Save The smectite whose occurrence is the clay coating in the sandstone of Xiagou formation in Ying’er sag is a kind of typomorphic mineral which can be used to predict reservoir physical properties. Using cast thin section analysis and SEM technology, the paper observes the occurrence of smectite coating and studies its forming mechanism and the influences on reservoir physical properties, in order to provide scientific basis for hydrocarbon exploration and development in Xiagou formation of Ying’er sag. The study shows that the smectite with poor crystal shapes adhered to the surface of clastic particles like capsules and became clay coating. The coating material came from the infiltrated atmospheric water carrying clay particles and the coating-forming time was after the calcite cementation during the early diagenesis stage A. Smectite coating coexists with quartz cements and the quartz cements are sparsely distributed or cover the surface of the smectite coating as the secondary enlarged edges of quartz. Therefore, the smectite coating growing on the wall of pores can’t inhibit the secondary enlargement of quartz, and make no contributions to the preservation of pores in sandstones, but it is a good typomorphic mineral to indicate physical properties of sandstones Related Articles | Metrics

Comprehensive Evaluation of Weathering Crust Structure of Metamorphic Rocks Based on Log Data:A Case from Bozhong X Structure in the Southern Bohai Sea CHEN Xinlu, WANG Yuechuan, PENG Jingsong, YE Tao, GAO Kunshun 2019, 40 (2):  1-1.  doi: 10.7657/XJPG20190209 Abstract ( 140 )   PDF (300KB) ( 491 )   Save Great discoveries have been achieved successively in the buried-hill reservoirs of metamorphic rocks in Bohai area, but there are lack of targeted methods to study weathering crust of metamorphic rocks. Taking the weathering crust of metamorphic rocks in Bozhong X structure in the Bohai Sea as the study object, and based on thin section observation, logging data, element mud log data, characteristic element extraction and clustering analysis, a set of quantitatively comprehensive evaluation methods is established for weathering crust, which can clearly identify and classify vertical structures of metamorphic rock weathering crust. The method has been applied in the newly drilled Well B and 4 zones are classified from top to bottom, i.e., weathering crush zone, strongly weathering fracture zone, weak weathering fracture zone and unweathering fracture zone, which provides references for the exploration in the area Related Articles | Metrics

Internal Configuration of Meandering River Point Bar in the Fifth Member of Guntao Formation in the Western District 7, Gudong Oilfield CHEN Depo1, LIU Huancheng2, CHEN Shuning3 2019, 40 (2):  1-1.  doi: 10.7657/XJPG20190210 Abstract ( 136 )   PDF (300KB) ( 348 )   Save The Fifth member of Guantao formation is the main oil layer in the western District 7 of Gudong oilfield and the reservoir belongs to loose sandstones of meandering river deposition. At present, the remaining oil saturation of the target zone in newly-drilled wells is not consistent with the expected one during the oilfield development, so the original designed objects cann’t be achieved. The effects of well adjustment and potential tapping in the existing wells don’t match with the geological understanding, which increases the difficulties of oilfield stimulation and it is urgent to verify the relationship between the internal configuration elements of meandering-river point bar reservoirs and the remaining oil distribution. Based on the study of the cores obtained from sealed coring wells, the paper summarizes the amount of the lateral accretion layers and rock types within the point bar, analyzes the flowing characteristics of the lateral accretion layers with different lithologies and the remaining oil distribution within the point bar, unravels the key elements of the internal configuration of the point bar, obtains the thickness, occurrence and distribution of the lateral accretion layer, and then calculates the length and width of the point bar and the depth and full shore width of the meandering river. Based on the data of logging, core and lab analysis, the internal configuration of the point bar in paired wells is analyzed and the high remaining oil saturation in the newly-drilled wells adjacent to water injection wells is reasonably explained. The study results show that the internal configuration of the point bar is the most important factor controlling remaining oil distribution and the remaining oil is mainly distributed in the reservoirs above the lateral accretion layers with relatively poor physical properties Related Articles | Metrics

Nitrogen Assisted Steam Stimulation Technology for Mid-Deep Heavy Oil Reservoirs ZHONG Liguo, WANG Cheng, LIU Jianbin, WANG Caixia, WU Wenwei 2019, 40 (2):  1-1.  doi: 10.7657/XJPG20190211 Abstract ( 165 )   PDF (300KB) ( 396 )   Save Due to the problems encountered in mid-deep heavy oil reservoirs such as high formation pressure, large heat loss during steam injection, small expansion of steam chamber and poor steam injection effect and so on, nitrogen assisted steam stimulation technology is presented, which is an improved steam stimulation technology. In this paper, experiments and numerical simulations were conducted to research the mechanism of nitrogen assisted steam stimulation and to optimize the injection parameters for the target reservoir in Bohai oilfield. Production mechanisms of nitrogen assisted steam stimulation including viscosity reduction by heating, viscosity reduction by gas solution, gravity displacement, pressurizing, steam chamber expanding, flow behavior changing and water controlling during nitrogen injection into the reservoirs with bottom water are researched, and the key injection parameters such as gas/water ratio, steam injection volume and injection mode are optimized. The numerical simulation results show that when the injection temperature is 350 ℃, the optimum gas/water ratio is 50; the steam injection strength in horizontal wells is 10~15 m3/m for the reservoirs with the thickness of 10 m Related Articles | Metrics

Limits of SAGD Fast Start-Up Technology for Heterogeneous Super Heavy Oil Reservoirs: A Case Study of Super Heavy Oil Reservoir of Jurassic Qigu Formation in Fengcheng Oilfield ZHAO Rui, LUO Chihui, ZHANG Yu, QI Mingxia, MENG Xiangbing, GAN Shanshan 2019, 40 (2):  1-1.  doi: 10.7657/XJPG20190212 Abstract ( 169 )   PDF (300KB) ( 286 )   Save Taking the super heterogeneous heavy oil reservoir of Jurassic Qigu formation in Fengcheng oilfield and using indoor rock mechanics experimental results, the paper establishes numerical models of coupled stress field, carries out numerical simulation analysis on SAGD fast start-up expansion process, and describes expansion features for the super heavy oil reservoirs. The results show that when the fast start-up ends, the porosity and the permeability in near-wellbore zones increase by 2% and 10%~100%, respectively, and the volume expansion rate can reach 1.74%, indicating the reservoir can be effectively expanded. Based on which, the influences of horizontal well trajectory, reservoir lithology and physical property on the fast start-up technology are studied, and the limits of SAGD rapid and uniform start-up technology are obtained. The study results reveal that the well groups with the following conditions can satisfy the fast start-up technology: no large mudstone section is developed along the horizontal section, the order differential of the permeability in the horizontal section is less than 3 and the vertical deviations between the upper and lower trajectory in the SAGD well are less than 1 m or the horizontal deviation is less than 2 m. The fast start-up technology should be implemented according to the actual situations of SAGD well groups and reservoirs during field practices Related Articles | Metrics

Steam-CO2 Flooding for Heavy Oil in District 9-6, Karamay OilfieldExperiment and Evaluation ZHOU Wei, KOU Gen, ZHANG Zixin, AN Ke, LIU Sai, LIU Yong 2019, 40 (2):  1-1.  doi: 10.7657/XJPG20190213 Abstract ( 239 )   PDF (300KB) ( 561 )   Save The recovery percent of reserves by steam flooding in the heavy oil reservoirs of the upper Qigu formation in District 9-6 of Karamay oilfield is 60%, but the recovery percent of reserves of the lower Qigu formation is only 32%. New development methods are needed to solve the problems of partial unswept reservoirs and large differences in reservoir producing degree, and further to improve development effect. Based on the indoor physical simulation experiments, this article studies the steam-CO2 flooding effect and oil displacement mechanism in District 9-6 and optimizes the injection parameters of the combined flooding. The experiment results show that CO2 can open the flowing channel for steam flooding and reduce the steam injection pressure, meanwhile it can inhibit the forming of the high-viscosity water-in-oil emulsion resulted from steam flooding and reduce crude oil viscosity; the water from steam condensation forms a water-alternating-gas slug, which can slow down the CO2 channeling and increase the swept volume. The enhanced oil recovery of steam-CO2 flooding is 35.0% higher than that of steam flooding and it is proved that the steam-CO2 alternating injection is the best injection mode. When the steam temperature is at 220 ℃ and the steam-CO2 volume ratio ranges from 10：1 to 25：1, the final oil displacement efficiency can reach 80% Related Articles | Metrics

Influences of Reservoir Heterogeneity on Gas Channeling During CO2 Flooding in Low Permeability Reservoirs JIA Kaifeng1, WANG Yuxia1, WANG Shilu1, JI Dongchao2a, LIU Bin2b, ZHANG Ruiyao1, GAO Jindong1 2019, 40 (2):  1-1.  doi: 10.7657/XJPG20190214 Abstract ( 260 )   PDF (300KB) ( 1221 )   Save In order to improve the oil recovery of CO2 flooding in low-permeability reservoirs and inhibit the CO2 channeling, the paper studies the influences of reservoir heterogeneity on gas channeling during CO2 flooding through laboratory experiments. On the basis of the experimental results, the characteristics of the oil production, ultimate oil displacement efficiency, gas breakthrough time, gas channeling time and pressure drop of different models are analyzed. The results show that vertically, the smaller the permeability contrast is, the later the gas channeling time will be; horizontally, the results of the model with high injection rate and low recovery factor are better than that with low injection rate and high recovery factor, that is, the higher the permeability at the inlet end，the later the CO2 channeling time, the better the oil displacement effect. The study result provides a beneficial support for the low permeability reservoir development in the Ordos basin Related Articles | Metrics

Properties of Ochrobactrum of Crude Oil Degrading Bacteria and Strain Screening XU Bing1,2, YU Li3, MA Yuandong3, HUANG Lixin3, LIU Bin1,2, WANG Tianyuan1,2, FU Ying1,2 2019, 40 (2):  1-1.  doi: 10.7657/XJPG20190215 Abstract ( 201 )   PDF (300KB) ( 461 )   Save A type of strain with crude oil degradation and emulsification characteristics was screened and separated from the formation water in District Liuzhong, Karamay oilfield, which should belong to Ochrobactrum according to the characteristics of physiology and biochemistry and 16SrDNA sequence analysis. Experimental study shows that the optimum pH value, temperature and salt tolerance for the bacteria growth are 6~9, 25~37 ℃ and 0~5%, respectively. The crude oil is the sole carbon source, the emulsification index of the strain fermentation liquor reaches 52% and steps into a stable stage after 66 h, which can consume the saturated hydrocarbon, aromatic hydrocarbon and light components in crude oil and then the relative content of saturated hydrocarbon in crude oil decreases from 68.00% to 53.73%, the relative contents of aromatic hydrocarbon, non-hydrocarbons and asphaltene increase from 11.04%, 14.10% and 6.86% to 12.44%, 24.81% and 9.02%, respectively; w（C21-）/w（C22+） and w（C21+22）/w（C28+29） reduce from 1.41 and 2.35 to 0.88 and 0.44, respectively; Pr/nC17 and Ph/nC18 increase from 1.53 and 1.70 to 13.43 and 35.00, respectively. The crude oil is degraded by the strain effectively, which provides possibilities for its further application in field oil displacement test and contaminated soil restoration. Related Articles | Metrics

Study on Proppant Backflow Based on Finite Element Simulation CAO Guangsheng1, BAI Yujie1, DU Tong1, YANG Tingyuan1, YAN Hongyang2 2019, 40 (2):  1-1.  doi: 10.7657/XJPG20190216 Abstract ( 279 )   PDF (300KB) ( 531 )   Save Hydraulic fracturing is a kind of most commonly used well stimulation technology. Under the same formation conditions and same fracture dimensions, the amount and distribution of proppant in fractures will change the flow conductivity of fractures and impact well production. At present, there are few researches on proppant distribution and flow in fractures during flowback after fracturing. The paper analyzes the influences of various factors on proppant amount in fractures through proppant flow simulation in fractures with the software COMSOL. The simulation result shows that the most important factor influencing proppant retention is the flow rate of fracturing flowback fluid and the viscosity of fracturing fluid after gel breaking and the adjustment of flowback parameter can inhibit the backflow of proppant. It is suggested that during fracturing the flowback fluid viscosity should be kept below 20 mPa·s and the fracturing fluid flow rate at 240 m3/d Related Articles | Metrics

Application of Intensive Staged Fracturing Technology in Deep Shale Gas Well Zi-2 FAN Yu, ZHOU Xiaojin, ZENG Bo, SONG Yi, ZHOU Nayun, CHEN Juan 2019, 40 (2):  1-1.  doi: 10.7657/XJPG20190217 Abstract ( 304 )   PDF (300KB) ( 697 )   Save Deep shale reservoirs are characterized by high temperature, high in-situ stress and large horizontal stress difference. After the implementation of conventional staged fracturing, the stimulated reservoir volume is usually relatively small, the level of fracture complexity and the test yield of gas wells are low. It is concluded that high pump injection pressure and low flow rate during the staged fracturing are the main reasons leading to insufficient reservoir stimulation in deep shale gas wells. To improve the adaptability of the technology and the effect of reservoir stimulation, the study on fracturing optimization for deep shale gas is carried out. The simulation results show that the intensive staged fracturing is good for increasing stress interference between clusters and improving both fracture complexity and stimulated reservoir volume. The conventional staged fracturing technology was initially adopted in the Well Zi-2, and then a field test for intensive staged fracturing was carried out. The test results show that the fracture complexity and stimulated reservoir volume are significantly improved, indicating the applicability of the intensive staged fracturing technology in the deep shale gas wells in the study area Related Articles | Metrics

Recognition of Single Channel Sandbody of Meandering River with Logging-Seismic Combination FAN Xiaoyi1a,2, XUE Guoqin1b, LIU Bin3, HUANG Yintao4, XIE Qi3, LI Weicai3 2019, 40 (2):  1-1.  doi: 10.7657/XJPG20190218 Abstract ( 168 )   PDF (300KB) ( 387 )   Save The sedimentary system of the Neogene Shawan formation in Chunguang oilfield is dominated by meandering river deposits. Due to the continuous river channel migration and diversion, frequent vertical superposition of sand bodies and sparse well pattern, it is hard to identify the boundary of a single channel. Besides, the oil-water relationship is contradictory in some wellblocks, which limits the further remaining oil potential tapping. To detailedly characterize the single channel boundaries and achieve the goal of fine oil and gas development and on the basis of logging responses, the paper concludes four typical indicators to depict the boundary of single channel, establishes an original geological model and summarizes seismic identification indicators. According to the responses of sandstone and mudstone on the strata slices, the distribution characteristics and development positions of single channels of different periods are identified. The logging-seismic combination method can overcome the uncertainty of lateral logging data prediction and improve the accuracy of single channel characterization.Keywords: Related Articles | Metrics

Dynamic Analysis on Unsteady Pressure of Composite Gas Reservoirs With Consideration of Threshold Pressure Gradient HUANG Yu1, LI Xiaoping1, TAN Xiaohua1, ZHANG Jiqiang2, YANG Guochao3 2019, 40 (2):  1-1.  doi: 10.7657/XJPG20190219 Abstract ( 175 )   PDF (300KB) ( 335 )   Save The existence of threshold pressure gradient in the flow process of low permeability gas reservoirs makes its flow mechanism more complicated than that of the conventional gas reservoirs. Moreover, due to acidizing, fracturing and some inherent features of gas reservoirs during the development of low-permeability gas reservoirs, there are some differences in the rock and fluid properties between the near wellbore areas and far-from-wellbore areas, resulting in the formation of composite gas reservoirs. Therefore, the paper establishes a unsteady flow model considering the threshold pressure gradient for horizontal wells in composite reservoirs, and obtains dimensionless analytical solutions of the model by using complex mathematical methods such as Laplace transformation and orthogonal transformation. Based on which, the influences of threshold pressure gradient, horizontal section length, mobility ratio and inner radius on the dynamic characteristics of the unsteady pressure in horizontal wells in the composite reservoirs are also studied. The results show that the pressure response type curves of the proposed model can be divided into 7 stages such as wellbore storage stage, transitional flow stage after wellbore storage, early vertical radial flow stage, mid-term linear flow stage, inner-zone pseudo-radial flow stage, transitional flow stage from inner zone to outer zone and outer-zone pseudo-radial flow stage. The higher the threshold pressure gradient, the larger the up-warping amplitude of the pressure response type curve; the longer the horizontal section length, the lower the position of the type curve; the bigger the mobility ratio, the higher the position of the type curve; the larger the inner zone radius, the longer the duration of inner-zone pseudo-radial flow stage will be. This research enriches the theories related to unsteady flow in low-permeability composite gas reservoirs, and provides a theoretical basis for a better understanding of the flow characteristics and for efficient development of gas reservoirs Related Articles | Metrics

Laumontite Cementation Characteristics and Their Influences on Reservoir Physical Properties in Chang 6 Member of Qilicun Oilfield, Ordos Basin DU Guichao1, SHI Lihua2, MA Xiaofeng3, CAO Qing1, DING Chao1, SHEN Zhenzhen4 2019, 40 (2):  1-1.  doi: 10.7657/XJPG20190208 Abstract ( 152 )   PDF (300KB) ( 357 )   Save To deepen the understandings about geological features of oil and gas in Qilicun oilfield, regarding laumontite development, cementation mechanism and their influences on reservoir physical properties in Chang 6 member of Yanchang formation and based on the porosity and permeability analysis, thin section identification and SEM analysis, the paper performs a systematic study on the diagenesis of sandstones in Chang 6 member. The results show that 3 stages of laumontite are developed in the Chang 6 member, namely syndiagenetic, early diagenetic stage A and late diagenetic stage A. In the syndiagenetic stage, laumontite cementation was mainly influenced by sedimentary environment and provenance, and the hydrations of metamorphic debris and vitric minerals in igneous rock debris in the sandstone of Chang 6 member provided enough materials for the generation of the early laumontite. In the early diagenetic stage A, albitization of anorthose provided the important material basis for the cementation of laumontite. In the late diagenetic stage A, the cementation was related to the oversaturated precipitation of laumontite, and the Ca2+ and SiO2 came from the dissolutions of early laumontite, feldspar and debris. The laumontite cementation was closely related to the reservoir physical properties of Chang 6 member. The early laumontite cementation prevented debris from further compaction and also provided favorable conditions for the formation of secondary pores during late dissolutions. The dissolution of the laumontite expanded the pore spaces of the reservoir and improved the pore throat structure and connectivity during the late diagenetic stage A Related Articles | Metrics

Fluvial Facies Styles and Their Sedimentary Facies Models ZHANG Jinliang 2019, 40 (2):  1-1.  doi: 10.7657/XJPG20190220 Abstract ( 808 )   PDF (300KB) ( 1506 )   Save The paper carries out the sedimentological analysis on fluvial styles and divides the channel system into single channel and multiple channel (or composite channel) systems. Straight channel, meandering channel and braided channel belong to single channel system, while anastomosed channel and other distributive fluvial systems belong to multiple channel system. Thick point bar, channel thalweg-filling sediment and counter point bar are the parts of meandering fluvial facies. An upward-finning meandering channel sequence is mainly composed of several microfacies such as thalweg deposit, sand bar complexes and over-bank fines. The architecture of a braided channel sandbody is very complex, and various large scale bedforms are distributed crisscrossly, the sandbodies in the channel can be divided into mid-channel sand bar, mid-channel sand sheet and several non-framework microfacies. The anastomosed river may be composed of braided river, meandering river and straight river, in another word, the single channel of anastomosed river can be divided into bedload channel, mixed-load channel and suspended-load channel. Terminal fan, meandering river fan, braided river fan and even some subaerial delta systems can be summarized into the distributive fluvial system. In fact, in the distributive fluvial system, the nature of the river has changed and the channel has been transformed from a confined channel to an unconfined channel. The concept of the distributive fluvial system is too general and broad, across the boundaries of different systems. There are many limitations in precise characterization of fluvial microfacies due to the great differences among different fluvial sand bodies Related Articles | Metrics