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01 January 2019, Volume 36 Issue 6 Previous Issue    Next Issue

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Geological Characteristics and Exploration Practice of Tight Oil of Lucaogou Formation in Jimsar Sag KUANG Lichun1, WANG Xiatian2, GUO Xuguang2, CHANG Qiusheng2, JIA Xiyu2 2015, 36 (6):  1-1.  doi: 10.7657/XJPG20150601 Abstract ( 210 )   PDF (300KB) ( 623 )   Save The Jimsar sag is formed in the late Hercynian period, transformed strongly in Yanshanian period, and shaped in Himalayan period. Today it’s a half graben?like sag with fault in the west and overlap in the east. The Middle Permian Lucaogou formation distributs in the whole sag with the major sedimentary assemblage of saline shallow lake and deep lake facies. High?quality hydrocarbon source rocks are in the Lucaogou formation, and the organic matter type is mainly the mixed organic matter of Type Ⅰ and Type Ⅱ1 during mature stage.Compared with the tight oil in other regions, sweet spots of tight oil in Lucaogou formation have characteristics of thin monolayers and large vertical span with two concentrated sections of them. For sweet spots reservoir, the predominant lithology is dolomitic fine?silty sandstone,the porosity of core in net confining stress averages 10.8%, the permeability of it ranges from 0.001 mD to 0.6 mD, being dominated by dissolved micropores. Related Articles | Metrics

Sedimentary Characteristic and Facies Evolution of Permian Lucaogou Formation in Jimsar Sag, Junggar Basin SHAO Yu1, YANG Yongqiang2, WAN Min1, QIU Longwei2, CAO Yingchang2, YANG Shengchao2 2015, 36 (6):  1-1.  doi: 10.7657/XJPG20150602 Abstract ( 126 )   PDF (300KB) ( 498 )   Save The systematic studies of the sedimentary characteristic and sedimentary facies of the Permian Lucaogou formation in Jimsar sag of Junggar basin are based on the available cores, thin sections and logging data. The results show that this formation was affected by the charging of terrigenous detrital, volcanic activity and endogenous carbonate rocks, and dominated by dolomitic rock with complex rock components and varied structures. The lacustrine basin gradually changed from early open lake basin to late closed lake basin. The dessert spots are mainly distributed in such sedimentary environments as delta, underwater bank, mixed flat and dolomitic flat, etc, and characterized by thin silty layer, high contents of quartz, feldspar, carbonate mineral, and low content of clay minerals. The lower sweet spot interval has high contents of quartz and feldspar, while the upper one has high content of dolomite, between which the deposits of semi-lacustrine lake mud and gravity flow occur. Because of the periodical change of climate, the deposits appear in ring strips along lake rim to the lake center with strong heterogeneity in the vertical. In the Lucaogou formation sedimentary period, a lot of volcanic materials were carried by wind into the lacustrine basin, resulting in a mix of normal sediment, volcanic and terrigenous detrital materials in the basin Related Articles | Metrics

Hydrocarbon Accumulation Conditions and Enrichment Regularity of Low-Permeability Glutenite Reservoirs of Baikouquan Formation in Mahu Sag, Junggar Basin LEI Dewen, QU Jianhua, AN Zhiyuan, YOU Xincai, WU Tao 2015, 36 (6):  1-1.  doi: 10.7657/XJPG20150603 Abstract ( 97 )   PDF (300KB) ( 441 )   Save Low-permeability glutenite reservoirs of Baikouquan formation are the major targets for petroleum exploration in Junggar basin.Five reservoirs of the Triassic Baikouquan formation have been found and proved in west slope zone of Mahu sag in the basin. The comprehensive study suggests that the west slope zone is of four favorable conditions for hydrocarbon accumulation: several sets of high-quality source rocks of the Permian continuously provide hydrocarbon for the reservoir; dessert spots occur in the low permeability reservoirs; high efficient transport systems are shaped by deep faults and unconformities, and the regional cap rocks are developed here. Also, the fan delta frontal facies belts distributed in this area have better reservoir property, there exist multistage hydrocarbon charging and good preservation conditions for late highly matured hydrocarbons, and the oil is lighter and contains natural gas, all of which could be the main reasons for its hydrocarbon enrichment Related Articles | Metrics

Sedimentary Facies of Palaeogene Ziniquanzi Formation in Mahe Gas Field in Southern Margin of Junggar Basin ZHU Jian, WANG Xiaojun, WU Baocheng, JIANG Yuangang, GAO Yang, XIE Zongrui 2015, 36 (6):  1-1.  doi: 10.7657/XJPG20150604 Abstract ( 62 )   PDF (300KB) ( 133 )   Save This paper analyzes the sedimentary structural setting and sedimentary facies symbol of Ziniquanzi formation of the Paleogene in southern margin of Junggar basin, and suggests that the Ziniquanzi formation in this area appears braided river delta deposits, and develops such three subfacies as delta plain, delta front and prodelta as well as eight microfacies like underwater distributary channel and others. The overall displays the evolution characteristics of lake regression and transpression. The contrast of the sedimentary facies, petrophysical property and productivity performance indicates that the most favorable sedimentary microfacies is the underwater distributary channel Related Articles | Metrics

Fluvial Changes and Sandbody Distribution of Toutunhe Formation in Cainan Area,Junggar Basin LI Shengli1, YU Xinghe1, YANG Zhihao1, DONG Xuemei2, ZHANG Tong2, ZHOU Yue1, LI Ying1 2015, 36 (6):  1-1.  doi: 10.7657/XJPG20150606 Abstract ( 88 )   PDF (300KB) ( 329 )   Save The Toutunhe formation in Baijiahai swell in Junggar basin is a typical fluvial-flood plain deposit. Its fluvial changes and sandbody distribution have been lack of in?depth studies, which restricts the oil and gas exploration and development of it. This paper clarifies the paleo?fluvial types and sedimentary sequences of Toutunhe formation by observation of the outcrops, presents corresponding sedimentary model; integrating with the well logging data and seismic attributes, it studies the identification characteristics, sedimentary evolution and sandbody distribution regularity of this fluvial deposit. The results show that such a distribution and evolution is mainly controlled by topographic slope and sediment supply. In the lateral expansion direction of the channels, the fluvial deposit is mainly controlled by topographic slope; while along the provenance direction, the sediment supply becomes major controlling factor, The fluvial sand bodies are predominately distributed in the east and west parts of the study area and major distribution of sandbody direction is from north to south Related Articles | Metrics

Restudy on the Age of Karamay Formation in Northwestern Margin of Junggar Basin LUO Zhengjiang1a, SHI Tianming1a, TANG Peng2,3, HUANG Pin3, ZHENG Daran3, WAN Mingli3, WANG Xu1b, YIN Yong4 2015, 36 (6):  1-1.  doi: 10.7657/XJPG20150607 Abstract ( 148 )   PDF (300KB) ( 88 )   Save The age and subdivision of the Triassic Karamay formation in the northwestern margin of the Junggar basin are quite different in references, which have negative impact on the related geological researches and thepetroleum production. Based on reserches on Trassic biostratigraphy and fossils collected by present work, this paper makes comprehensive studies on the biostratigraphy of surface and subsurface. By the discovery of Late Triassic Danaeopsis fecunda from the S7 sand unit of the lower member of the Karamay formation, this paper proposes that the age of the upper member of the Karamay formation in the northwestern margin of the Junggar basin should be Late Triassic, while that of the lower member of it should be late Middle Triassic to early Late Triassic; the boundary between the Middle Triassic and the Upper Triassic is located in the S7 sand unit. The Karamay formation overlies unconformably the underlying Baikouquan formation,and the deposits of late Early Triassic and early?middle Middle Triassic. The piedmont of the Zaire mountain appeared to be an eroded area in the Early?Middle Triassic and receive depositsin the Late Triassic, experiencing the evolution of the sedimentary facies from alluvial fan,braided river to lacustrine sedimentary systems. In the middle?late Late Triassic, the sedimentary stage of the Baijiantan formation was deposited in open lacustrine basin Related Articles | Metrics

Identification and Prediction of Glutenite Effective Reservoirs of First Member of Dainan Formation in Gaoyou Sag LIU Jinhua, LIAO Guangming 2015, 36 (6):  1-1.  doi: 10.7657/XJPG20150608 Abstract ( 69 )   PDF (300KB) ( 119 )   Save Based on the measured data of core porosity and the well logging acoustictravel time, the target plates of porosity and acoustic travel time in study area are presented, and determining the cut?off of porosity is 11%, that of acoustic travel travel time is 220 μs/m for the effective glutenite reservoirs. The study from sensitivity analysis of rock elastic parameters that S?wave velocity can be well used to distinguish the sandstone and mudstone in the first member of Dainan formation in Gaoyou sag, the density can be used to distinguish oil layer,water layer and dry layer. Using the prestack S?wave velocity inversion to predict the target zone’s lithology, the prestack P?wave velocity inversion to predict the effective reservoir’s porosity, and then making evaluation of rationality of those predicted results of net pay thickness and porosity, by which the effective reservoir’s net pay thickness and petrophysical property distribution regularities in the study area can be finally obtained Related Articles | Metrics

Techtonic Evolution of Halaalate Mountain Area and Implications in Petroleum Geology XUE Yan1,2, ZHANG Kuihua1, WANG Yihao3, WANG Shengzhu1, CHENG Shiwei1, SONG Meiyuan1 2015, 36 (6):  1-1.  doi: 10.7657/XJPG20150609 Abstract ( 88 )   PDF (300KB) ( 241 )   Save Hala抋late mountain area is a part of the piedmont thrust belt in northwestern margin of Junggar basin. The progress of oil and gas exploration in this area is seriously affected for its unclear tectonic process. Based on the 3D seismic data interpretation, field geologic survey and core geochemical analysis, the vertical tectonic evolution process in this area is reconstructed, and the controlling effect on the oil?gas accumulation is discussed. The results show that the tectonic evolution in Hala’alate area mainly went through such six stages as ancient oceanic crust subduction and collision (C2), expanding?rifted and early thrust?deformation (P1), strong thrust and nappe (P2), thrust and superimposition (T), oscilation and upswelling (J-K) and upswelling?erosion and strike?slip adjustment (Cz) ones. In the late Early Permian,under the stretched and rifted tectonic setting, thick source rocks are developed in this area; from Late Permian to Triassic, the strong thrust and nappe allow the reservoir petrophysical property to be improved, thus forming numerous structural traps; since Jurassic, the tectonic activity tends to rest, which plays a good conservation role in early forming reservoirs Related Articles | Metrics

Micro Pore Structure Characteristics of Tight Sandstone Reservoirs in Shengli Oilfield YIN Yanling, SUN Zhigang, WANG Jun, FANG Huichun, ZHANG Yuli, LIU Guiyang 2015, 36 (6):  1-1.  doi: 10.7657/XJPG20150610 Abstract ( 72 )   PDF (300KB) ( 101 )   Save This quantitative research of micro pore structure characteristics of the tight sandstone reservoirs is based on the reservoirs with permeability of less than 5 mD in Shengli oilfield, combined with the capillary pressure curve analysis and pore structure comparative analysis, in view of the tight reservoirs with similar air permeability but existing different complexities in water flooding process. The study results show that the key of understanding the tight sandstone pore structures in Shengli oilfield is the characterization of pore throat size and distribution, and the effectiveness of the throat radius. With the permeability decreasing, the proportion of those throats greater than 1.0 μm in radius is declining rapidly, while that of throats less than or equal to 0.4 μm is quickly increasing, which indicate that the throats of tight sandstone reservoirs in Shengli oilfield are too tiny and like to peak shape in distribution, compared to Daqing oilfield and Changqing oilfield, so such a case in Shengli oilfield will be unfavorable to reservoir development Related Articles | Metrics

Characteristics and Quantitative Prediction of Tectonic Fractures of Yingcheng Formation in Volcanic Reservoir of Anda Area in Songliao Basin GUO Peng1, YAO Leihua1, REN Desheng2 2015, 36 (6):  1-1.  doi: 10.7657/XJPG20150611 Abstract ( 54 )   PDF (300KB) ( 65 )   Save The key of exploration of a volcanic reservoir is to make clear the development and distribution of fractures in it. This paper presents the statistical analysis of the basic feature, the mechanical property and the effectiveness of the tectonic fractures in the volcanic reservoir of the Yingcheng formation in Anda area in Songliao basin, based on the outcrop, core and thin?section data of the volcanic rocks in this area. The results show that the Yingcheng reservoir mainly develops in regional conjugate tectonic fracture system to near?SN,NNW-SSE, NW-SE and near?EW directions, with core fracture linear density of 0.20~1.00 ribbons per ceti meter. The most tectonic fractures are tensional and half?filled. By 3D tectonic stress field simulation, combined with rock burst method and energy method, a quantitative prediction model for tectonic fracture distribution of Yingcheng formation in Anda area is developed, by which the favorable areas with developed tectonic fractures are predicted, providing important reference for further exploration and development of the volcanic rock reservoirs in this area Related Articles | Metrics

Fracture Characteristic and Its Contribution to Hydrocarbon Accumulation in Tight Sandstone Reservoir in Dibei Gas Pool in Kuqa Depression, Tarim Basin WEI Hongxing, XIE Yani, MO Tao, WANG Zuotao, LI Li, SHI Lingling 2015, 36 (6):  1-1.  doi: 10.7657/XJPG20150612 Abstract ( 68 )   PDF (300KB) ( 148 )   Save Dibei gas pool is located in eastern Kuqa depression, its reservoir rock is tight sandstone of the Jurassic Ahe formation. This paper makes observation of the Jurassic outcrop section, description of the drilling core, and statistics of the casting thin?section analysis data,and then determines that the reservoir space is dominated by intergranular dissolution pores and a lot of fractures in this reservoir rock.Through description and statistics of the outcrop fractures, it suggests that the fracture?developed degree is controlled by the regional location, lithology, sand body thickness, and tectonic stress intensity, etc. The gas drive water experiment on the tight sandstone cores indicates that fractures can greatly improve the charging efficiency of gas accumulation, thus forming higher gas saturation in fracture?developed area, and controlling the natural gas enrichment of Dibei gas pool Related Articles | Metrics

Lithology Logging Interpretation Model for Lacustrine Carbonate Rocks of the Es4 in Shaojia SubSag, Jiyang Depression, Bohai Bay Basin YANG Shengchao1, QIU Longwei1, LIU Kuiyuan2, XU Ningning1, YANG Yongqiang1, HAN Xiao3, JIANG Jiacheng4 2015, 36 (6):  1-1.  doi: 10.7657/XJPG20150613 Abstract ( 61 )   PDF (300KB) ( 195 )   Save To predict the lithology of lacustrine carbonate rocks is the key of predicting its favorable reservoir distribution. Based on the core data, thin sections, well logs and test information, and taking sedimentary facies as limited ranges, the rock?electrical identification model for the carbonate rocks of Es4 in Shaojia sub?sag is developed by means of the types of sedimentary facies. The study shows that in the Es4 of Shaojia sub?sag, several categories of carbonates occur in this area, such as reef dolomite, bioclastic limestone, calcarenite, oolitic limestone, micrite limestone, packstone, gypsum limestones, etc., and the main sedimentary types are reef, nearshore limestone bank and infralittoral limstone bank. The rocks and their logging characteristics in each facies are collected, followed by making lithology logging interpretation model for each facies. These models are applied to some well sections in this area, which indicate good results from thin?section verifications in identification accuracy and favorable carbonate reservoir prediction Related Articles | Metrics

Shale Compaction and Overpressure Distribution in Southeast Slope of Dongying Sag,Bohai Bay Basin YANG Bin1, ZHANG Likuan2, ZHANG Liqiang3, LEI Yuhong2, CHENG Ming2, YU Lan2 2015, 36 (6):  1-1.  doi: 10.7657/XJPG20150614 Abstract ( 58 )   PDF (300KB) ( 249 )   Save The shale compaction curves from 99 wells in southeast slope of Dongying sag are studied in this paper, indicating that the shale compactions are characterized by transverse zonation and longitudinal segmentation. In transverse section, the shale undercompaction zone is distributed in Niuzhuang sub?sag and Wangjiagang slope transitional belt, in which salient zones are all normal compaction ones, while in longitudinal section, the compaction can be devided into the undercompaction segment in the lower part and the normal compaction segment in the upper part. The undercompaction segment is mainly distributed in the second, third and fourth members of Shahejie formation with depth of 1 900~3 800 m; the normal compaction segment is in the second member and overlying strata. Also, the calculated shale fluid pressure and the measured sand fluid pressure show that the formation fluid pressure in the southeast slope is of obvious zonation: by taking the top of the third member as boundary line, the normal pressure section occurs in shallow part, while the abnormal overpressure section occurs in deep part. And such a shale overpressure appears in wide lateral distribution with strong inheritance, and the area with excess pressure high value is located in the Niuzhuang sub?sag. The overpressure is basically the same with the shale undercompaction in distribution. The overpressure scale of sandstone is somewhat less than that of shale. The abnormal pressure in southeast slope in Dongying sag belongs to deposit overpressure, and the shale undercompaction is the main mechanism of it Related Articles | Metrics

Diffusion Is Not the Production Mechanism of Shale Gas LI Chuanliang, ZHU Suyang 2015, 36 (6):  1-1.  doi: 10.7657/XJPG20150615 Abstract ( 43 )   PDF (300KB) ( 105 )   Save Diffusion is caused by concentration difference, while flow is by pressure difference. Concentration is a concept defined for solutions. Pure substances do not have the concept of concentration, thus there is no phenomenon of diffusion for them. If shale gas is viewed as a pure substance, there is no concept of concentration for it, in other words, diffusion phenomenon won抰 appear at all in it. If shale gas is viewed as a mixture, its composition won抰 be changed by any production process, so diffusion may not happen, too. Diffusion is defined for components in a solution, not for the solution, so "diffusion of shale gas" is not correct as a concept. The production of shale gas is actually the flow caused by pressure difference. During the production, reservoir pressure is usually monitored rather than concentration, hence the research on diffusion of shale gas has not any practical meaning Related Articles | Metrics

Approach to Deep Heavy Oil Viscosity Limit by Waterflooding Process: A Case Study of Wellblock Ji7 in Changji Oilfield, Junggar Basin XIE Jianyong, SHI Yan, LIANG Chenggang, WU Chengmei, LUO Hongcheng, WU Jianming 2015, 36 (6):  1-1.  doi: 10.7657/XJPG20150616 Abstract ( 52 )   PDF (300KB) ( 170 )   Save The thermal recovery process is not appropriate to deep heavy oil reservoir development due to economic and technical constraints. Some domestic heavy oil reservoirs developed by conventional waterflooding process have achieved the better results. But with the crude oil viscosity increasing, the water flooding effect is getting worse and worse, and the recovery efficiency is lower than the related economic limit, this process is not suitable for such a reservoir. So viscosity is the key to determine whether such a reservoir is developed by waterflooding process or not. Wellblock Ji?7 in Changji oilfield of Junggar basin is a deep and large heavy oil reservoir with depth of 1 317~1 836 m and oil viscosity of 40~3 000 mPa·s. This paper makes field water flooding test and lab experiment to determine the limit of oil viscosity suitable for waterflooding process. It is suggested that the reservoir with formation oil viscosity less than 2 470 mPa·s can be developed by waterflooding process, which provides scientific basis for large?scale waterflooding development of Wellblock Ji?7 deep heavy oil reservoir Related Articles | Metrics

Influencing Factors of Crude Oil Properties in Lucaogou Tight Reservoir in Jimsar Sag,Eastern Junggar Basin PENG Yongcana, LI Yingyana, MA Huishua, YANG Kunb, LIU Jianc, CHEN Yingxiaod 2015, 36 (6):  1-1.  doi: 10.7657/XJPG20150605 Abstract ( 60 )   PDF (300KB) ( 199 )   Save The tight reservoir of Lucaogou formation is a near?source oil pool with both source and reservoir in Jimsar sag, where there exist two sweet spots being 100 meters apart in the vertical. They belong to saline lacustrine deposits with big difference of fluid property. The crude oil in the lower sweet spot is much heavier than that in the upper one. Focusing on this feature of unusual distribution in crude oil property, this paper analyzed their kerogen type, oil source, source rocks’thermal evolution and oil biodegradation, and reveals the reasons for the partial thick crude oil and differential distribution in this area Related Articles | Metrics

Effect of Low Carbon Alcohols on Foaming Performance of Olefine Sodium Sulfonate Solution with Low Mass Fraction CHEN Zehua, ZHAO Xiutai 2015, 36 (6):  1-1.  doi: 10.7657/XJPG20150617 Abstract ( 52 )   PDF (300KB) ( 196 )   Save Low carbon alcohol is often used as additives for surfactant because of its better synergistic effect with surfactant. This paper investigates the effect of low carbon alcohol on the foaming performance of α?olefine sodium sulfonate solution with low mass fraction of 0.02%. The result shows that the synergistic effect of this solution with high mass fraction of 0.2% is not obvious on the low carbon alcohol;there exist obvious synergistic effects between the α?olefine sodium sulfonate solution with low mass fraction of 0.02% and such three alcohols as isopropanol, n?butyl alcohol and isoamyl alcohol, respectively, showing that these alcohols can greatly improve the foaming performance of low mass fraction sulfonate solution, and with the increasing of the carbon number of alcohols, the foaming performance becomes better and better, except for methanol and ethanol. Also, NaCl and CaCl2 with high mass fraction may not be directly used to improve the foaming performance of the solutions with low mass fraction, while isoamyl alcohol can do it well in presence of the NaCl and CaCl2, and with the increasing of isoamyl alcohol’s mass fraction, the synergism effect also becomes better and better Related Articles | Metrics

Application of VerticalHorizontal Steam Drive Process to Fengcheng ExtraHeavy Oil Reservoir, Junggar Basin QIAN Genbao1, SUN Xinge2, ZHAO Changhong2, WANG Tao1, YANG Zhaochen2, LI Lingduo2, XIONG Wei2 2015, 36 (6):  1-1.  doi: 10.7657/XJPG20150618 Abstract ( 129 )   PDF (300KB) ( 263 )   Save An extra?heavy oil reservoir developed by horizontal well steam drive process appears two states of steam flooding and gravity drainage in process of driving force and gravity, it is known as vertical well steam injection?horizontal well production steam drive (VHSD) process. This paper describes this mechanism, steam flooding mode, injection?production parameters and adjustment and control policy by means of analytical and numerical simulation methods. The study shows that in the area of Well Zhong?32 in Fengcheng oilfield, the suitable operation conditions for the Qigu extra?heavy oil reservoir developed by VHSD process are that vertical well uses rotating steam injection with steam injection rate of 70 t/d, steam quality at the bottom of higher than 70%, operation pressure of 2.5 MPa, and production/injection ratio of 1.2. The main control technique is the optimization of steam injection spot, sub?cool regulation, injection?production balance and working system optimization. The expected recovery efficiency can reach 50% Related Articles | Metrics

Method for Reasonable Well Spacing Evaluation of MediumLow Permeability Conglomerate Reservoirs in Karamay Oilfield YANG Xinping, ZHANG Lifeng, YANG Zuoming, LUO Guanxing, YANG Xu, WANG Yang 2015, 36 (6):  1-1.  doi: 10.7657/XJPG20150619 Abstract ( 81 )   PDF (300KB) ( 110 )   Save Four main controlling factors of the reasonable well spacing for medium?low permeability conglomerate reservoirs in Karamay oilfield are determined by means of mathematical statistics, reservoir engineering and characteristic model orthogonal experiment, etc. They are sand?body morphology, permeability variable coefficient, permeability and oil displacement efficiency. The weight variation regulation of these main controlling factors are found by multi?factor sensitivity analysis in different stages, and then the staging evaluation mathematic models for reasonable well spacing of medium?low permeability conglomerate reservoirs are developed. The case study verifies the accuracy of these models, which can provide basis for scientific evaluation of such a reasonable well spacing and further development adjustment in the future Related Articles | Metrics

Optimization of Methods for Predicting Liquid Loading in Deep Condensate Gas Wells ZHOU Chao1, WU Xiaodong1, LIU Xiongwei2, HUANG Cheng2, CHEN Biao2 2015, 36 (6):  1-1.  doi: 10.7657/XJPG20150620 Abstract ( 77 )   PDF (300KB) ( 253 )   Save Liquid loading is a serious problem for normal production of gas wells in Yakela-Dalaoba deep condensate gas reservoir. The applicability of common methods for predicting liquid loading still needs to be demonstrated. The applicability of critical rate method and kinetic energy factor method is evaluated and opimized. The fundamental principles of each method for predicting liquid loading and differences among them are introduced. Different dynamic distribution of critical rate and surface tension along wellbore are considered in order to improve original critical rate models. Through error analysis, the methods suitable for calculating temperature and pressure distribution in high and low gas?liquid ratio wellbores of Yakela-Dalaoba gas reservoir are optimized respectively, and such methods suitable for predicting liquid loading are given through field case study. Results show that modified pseudo single?phase coupling model is suitable for calculating temperature and pressure distribution in high gas?liquid ratio wellbore, while Hagedorn?Brown method and Hasan method are suitable for it in low gas?liquid ratio wellbore of Yakela-Dalaoba gas reservoir. The improved critical rate models increase precision of liquid loading prediction compared to original models. The improved Li Min model and kinetic energy factor method that sets threshold value as 6 are of the highest precision, and both of them are suitable for predicting liquid loading of gas wells in Yakela-Dalaoba deep condensate gas reservoir Related Articles | Metrics

Approach to Space Position of Seismic Imaging for Complex Surface CHEN Zhigang1, ZHANG Jian1, CHEN Miaoyu2, CUI Qin1, WANG Xiaotao1, MA Junyan1 2015, 36 (6):  1-1.  doi: 10.7657/XJPG20150621 Abstract ( 54 )   PDF (300KB) ( 149 )   Save The area of non horizontal surface and varied surface structures compared with the area of horizontal surface and stable surface structure may have big changes in incident angle and emergent angle of seismic ray, so its space position of seismic imaging obtained by existing methods may have big horizontal displacement by comparing with real formation space location. This study suggests that for non horizontal surface, the structural space position displayed by seismic profile is in error, compared with the real geologic structure location, and the offset distance can be given by X=hsinθ; for horizontal surface, but the surface structure is in big lateral changes, the structural space position given by time domain seismic profile is also in error compared with the real structural location. In complex surface area, static correction should take account of the changes of incident and emergent angles, which may cause the changes of time-distance curves, otherwise, it will allow the problem not belonging to static correction to be more complicated, thus influencing the follow?up work. Therefore,complex surface imaging method including surface relief and surface structure lateral changes is the key of precise seismic imaging for complex surface area; the time-depth conversion for non horizontal surface area should take account of the matching of seismic profile (including velocity profile) and real structural space location Related Articles | Metrics