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01 January 2019, Volume 38 Issue 3 Previous Issue    Next Issue

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Development of Large-Scale Shallow-Water Fan Delta: Sedimentary Laboratory Simulation and Experiments TANG Yong1, YIN Taiju2, QIN Jianhua1, WANG Dongdong2 2017, 38 (3):  1-1.  doi: 10.7657/XJPG20170301 Abstract ( 107 )   PDF (300KB) ( 295 )   Save Hundreds of millions of OOIP discovered in the area around Mahu sag, Junggar basin reveals the giant oil and gas potential in the area. Exploration practice shows that the sedimentary system in the area around Mahu sag which is different from that of alluvial fan previously found is a set of shallow-water, gentle-slope fan delta system. To deeply understand the depositional characteristics and formation mechanism of this system and based on flume simulation device in Yangtze University, simulation and experiments are carried out for the formation process of the sedimentary system. In the experiment, 3 levels of slope-break and 3 periods of lake level change are set, which correspond to 3 depositional periods of T1b1, T1b2 and T1b3, respectively, and gravity flow and tractive current are used to simulate the process of fan body formation. The modeling result shows that a kind of retrograding sequence was formed due to the rise of lake level, resulting in obvious overlapping of sequences. The investigation on reservoir internal structures indicates that laminated interactive deposits of gravity flow and river are more commonly found in the fan-delta plain, and the deposits of tractive current and secondary gravity flow resulted from progradation occur in the fan delta front. The boundaries of fan bodies caused by gravity flow and progradation in different periods are not clear and it is difficult to distinguish them. Lake level, slope-break, sedimentary energy(elevation of ancient landform) and the compositions of deposits have significant influences on fan development during the deposition process Related Articles | Metrics

Discussions on Sandstone Densification TimeA Case Study from Shanxi Formation in Zhidan Area, Ordos Basin LI YanxiaLIU Jieqi 2017, 38 (3):  1-1.  doi: 10.7657/XJPG20170302 Abstract ( 54 )   PDF (300KB) ( 210 )   Save By means of polarized-light and fluorescence microscopes, petrological characteristics of the tight sandstones of Shanxi formation in Zhidan area, Ordos basin are observed. Meanwhile, temperatures of the inclusion in the quartz overgrowth edges are measured by using microscopic heating-freezing stages and components of the inclusion are analyzed with laser Raman spectroscopy. The study shows that four types of inclusions are developed in the quartz overgrowth edges of the tight sandstones in Shanxi formation of Zhidan area, namely, inorganic brine inclusion, hydrocarbon-bearing brine inclusion, gaseous and liquid hydrocarbon inclusion, and gaseous hydrocarbon inclusion. The homogenization temperature of the brine inclusion occurred in the quartz overgrowth edges of Stage Ⅰ ranges from 80℃ to 100℃ and its freezing temperature is -4~-2℃. Based on which, it is assumed that the quartz overgrowth edge was formed 200×106~190×106 years ago; brine inclusion in the quartz overgrowth edges of Stage Ⅱ has a homogenization temperature of 105~125℃ and freezing temperature of -6~-4℃, whose gaseous components are dominated by CO2 with minor C2H6, indicating the time for Stage Ⅰ natural gas charging and initial sandstone densification was 190×106~160×106 years ago. The homogenization temperature and freezing temperature of the brine inclusion in the quartz overgrowth edges of Stage Ⅲ are 135~155℃ and -10~-8℃, respectively. The gasceous components are dominated by CH4 and C2H6, accompanied by large amount of high-matured natural gas charging at the late stage. Then it is assumed that the time for natural gas accumulation and further sandstone densification occurred 160×106~140×106 years ago. Natural gas charging was accompanied by late-stage sandstone densification Related Articles | Metrics

Paleosalinity Restoration of Lower Triassic Baikouquan Formation in Mahu Sag, Junggar Basin HUANG Yunfei1a, ZHANG Changmin1a, ZHU Rui1a, YI Xuefei1b, QU Jianhua2, TANG Yong2 2017, 38 (3):  1-1.  doi: 10.7657/XJPG20170303 Abstract ( 106 )   PDF (300KB) ( 59 )   Save The Lower Triassic Baikouquan formation in the Mahu sag, Junggar basin is a set of sedimentary system of fan delta, which is dominated by coarse detrital deposits with a small amount of mudstones. In order to restore the paleosalinities of the water body during the deposition of the Baikouquan formation, and compared with those of the Upper Permian Wuerhe formation and Middle Triassic Kelamayi formation, whole rock tests of clay minerals and trace elements are carried out for the mudstone samples in the cores obtained from the above three formations. The methods such as Boron element, Sr/Ba ratio and B/Ga ratio are used to restore the water paleosalinities during the deposition of the Baikouquan formation. The results show that the clay minerals in the sample are dominated by illite/montmorillonite mixing layer, so Coach formula is suitable to be adopted to restore the paleosalinities. The average paleosalinities of the Upper Permian Wuerhe formation, T1b1, T1b2, T1b3 and Middle Triassic Kelamayi formation are 7.0‰, 5.0‰, 7.2‰, 8.9‰ and 8.4‰, respectively, indicating that the water at that time was fresh water-brackish water environment. The Baikouquan formation in Huangyangquan fan and Xiazijie fan exhibits different paleosalinity variation trend, relatively low paleosalinity of Huangyangquan fan and relatively high paleosalinity of Xiazijie fan may be related to the palaeosedimentary environment of the selected well locations. In addition, both Sr/Ba ratio and B/Ga ratio indicate a fresh water-brackish water environment in Mahu sag during Late Permian to Middle Triassic Related Articles | Metrics

Characteristics and Genesis of Fan Deltas of Xiazijie Formation in Halaalate Mountain Area, Junggar Basin CHEN Xueguo1, ZHONG Weiping1, XU Houwei2, ZHANG Guanlong1, WANG Youtao1 2017, 38 (3):  1-1.  doi: 10.7657/XJPG20170304 Abstract ( 69 )   PDF (300KB) ( 286 )   Save Middle Permian Xiazijie formation in the Hala’alate Mountain area of Junggar basin is a set of thick, near-source fan delta depositions, which are incised and superimposed vertically with a complex sedimentary framework. The comprehensive study result shows the fan deltas in the western part of Hala’alate Mountain are obviously different from the ones in the eastern part in facies markers, transportation mechanism and sand body characteristics and so on. Based on the core data, log data and analysis of petrophysical and electrical properties, it is considered that the near-mountain fan delta dominated by steep-slope gravity current is developed in the western part, and near-fan fan delta dominated by gentle-slope tractive current is found in the eastern part of the Hala’alate Mountain, and the two types of fan deltas have distinct reservoir properties and different distribution patterns, which could be a guidance for oil and gas exploration Related Articles | Metrics

Genesis of Sandy Conglomerate Reservoirs Cemented by Zeolites in Jiamuhe Formation of Zhongguai Swell, Junggar Basin WU Heyuan1,2a, TANG Yong2b, CHANG Qiusheng2b 2017, 38 (3):  1-1.  doi: 10.7657/XJPG20170305 Abstract ( 72 )   PDF (300KB) ( 209 )   Save The genesis of sandy conglomerate reservoirs cemented by zeolites is the key problem in the exploration of Permian Jiamuhe formation in Zhongguai swell, Junggar basin. Based on core observation and microscopic analysis, and combined with electron probe microanalysis, the paper analyzes the sedimentary facies and diagenesis, establishes the relationships among sedimentary environment, diagenetic environment and reservoir genesis, and discusses the genesis and mechanism of sandy conglomerate reservoirs of Jiamuhe formation in Zhongguai swell, Junggar basin. The sandy conglomerate reservoirs of Jiamuhe formation show some characteristics of tight reservoirs with low porosity and low permeability and the genesis of the reservoirs can be summarized as 4 points. First, a special sedimentary environment of alluvial fan was the basis of multi-type lithofacies formation. Second, the induction of ephemerally open and alkaline diagenetic environment provided the environment for the early zeolite cementation. Third, multiple and rapid alternation of acid and alkaline diagenetic environments was the key factor of secondary pore formation. Fourth, the long-term and enclosed alkaline environment was the most important reason for the densification of reservoirs. The sedimentary facies of Jiamuhe formation is dominated by fan-margin subfacies-mid-fan subfacies of pluvial-alluvial fan, and 4 types of sandy conglomerates cemented by zeolites formed under the combined actions of 6 sedimentary facies and multiple diagenesis. The reservoirs with the lithofacies of coarse grained-medium compaction-medium cementation-medium to strong cementation-dissolution under the control of underwater distributary channel of alluvial fan margin will be the most favorable reservoirs regionally, which will be the key targets for future petroleum exploration Related Articles | Metrics

Geochemical Characteristics and Genesis of Shale Gas in Chang 7 Oil Member of Fuxian Area, Ordos Basin WANG Hui, GAO Dongchen, YIN Jintao, ZHANG Lixia, JIANG Chengfu, SHI Peng 2017, 38 (3):  1-1.  doi: 10.7657/XJPG20170306 Abstract ( 95 )   PDF (300KB) ( 99 )   Save Taking the desorbed gas in the shale cores of the Chang 7 Oil Member in Well WX of Fuxian area, Ordos basin as the study object, the geochemical characteristics such as gas component, light hydrocarbon, carbon isotope and hydrogen isotope in the shale cores are studied, based on which the genesis of the natural gas are analyzed. The results show that the characteristics of gas component, light hydrocarbon composition, carbon isotope and hydrogen isotope of the shale gas are significantly different among samples obtained from different depths of the Chang 7 Oil Member in Well WX. With the increase of the depth, heavy hydrocarbon contents, relative contents of n-alkanes and isoalkanes in light hydrocarbons and the ratios of n-alkanes and isoalkanes contents to 1,1-dimethylcyclopentanes rise gradually, drying coefficient, naphthene hydrocarbon content and the ratio of naphthene hydrocarbon content to 1,1-dimethylcyclopentanes decrease gradually, carbon and hydrogen isotopes become lighter and the reverse degree of carbon isotope reduces. The shale gas in Chang 7 Oil Member of Well WX belongs to oil-type pyrolysis gases without the mixing with inorganic diagenetic gas and Paleozoic coal-type gas, suffering from different degrees of microbiological oxidization which becomes weaker from shallow to deep. The inhomogeneous microbiological oxidization is the main reason causing the vertical differences of gas component, light hydrocarbon composition, carbon and hydrogen isotopes and carbon isotope reversal in the shale gas of Well WX. Related Articles | Metrics

Discussions on Movable Hydrocarbons in Source-Rock Oil in the Second Member of Permian Lucaogou Formation, Santanghu Basin LI Xinning1, REN Jihong2, XIN Ming3, LIANG Hui1, ZHANG Pin1, MA Qiang1, ZHAO Sijun4 2017, 38 (3):  1-1.  doi: 10.7657/XJPG20170307 Abstract ( 70 )   PDF (300KB) ( 318 )   Save A set of tuffite hydrocarbon source rocks developed in the second member of Permian Lucaogou formation, Santanghu basin, is characterized by large thickness, high abundance of organic matters, good organic matter type, and being in the oil generation window. Self-generation and self-storage is the main hydrocarbon accumulation pattern, source rocks are the good pay zones which have the typical characteristics of hydrocarbon accumulation in source rocks. Evaluation of movable hydrocarbon content in reservoirs should be focused on during source-rock oil exploration. The paper discusses the qualitative and quantitative characterization of movable hydrocarbons in the source-rock oil by using mud log, quantitative fluorescence, rock pyrolysis and NMR technologies. The movable hydrocarbon resources are estimated quantitatively with rock pyrolysis method. The result shows that the movable hydrocarbon resource in the source-rock oil of Permian Lucaogou formation in Malang sag, Santanghu basin is 5.53×108 t, resource abundance reaches 300×104 t/km2, which demonstrates that there is great potential for source-rock oil exploration. Related Articles | Metrics

Validity Test of Reservoir Parameter Probability Distribution and Estimation of Petroleum Reserves in Oilfield A, Pearl River Mouth Basin TU Yi, LIU Weixin, DAI Zong, WAN Jun 2017, 38 (3):  1-1.  doi: 10.7657/XJPG20170308 Abstract ( 52 )   PDF (300KB) ( 121 )   Save For the districts with large trap areas and less well data, probability method is the most effective way to estimate entrapped petroleum resources. Firstly, the rationality of each geological parameter distribution model is checked with A-D test method, K-S test method and Chi-square (χ2) test for oilfield A in Pearl River Mouth basin. Meanwhile, the validity of reserves parameter distribution is tested with their geological meanings and related rules stipulated by SPE and SEC, based on which, a parameter probability distribution model suitable for oilfield A is established. Taking Z7 reservoir of oilfield A as an example, using the above mentioned methods and processes and considering the saddle-like trap configuration and low degree of well control in Z7 reservoir, shape factors are introduced to reduce the influences of irregular structural shape on reserves estimation. The case study shows that quantitative probability distribution of each reserves parameter can be obtained by using the probability method, which is helpful for uncertainty analysis of factors influencing reserves estimation; and more objective and comprehensive evaluations on petroleum resource potential and risks could be made. The calculated reserves obtained from probability method and deterministic method are close to each other in Z7 reservoir, with the error less than 2%. The study shows that the reserves estimation method presented in this paper has certain guidance significance for resource evaluation in the districts with large trap areas and less well data. Related Articles | Metrics

Genesis and Identification of Sandstones with High Gamma Values in the Second Member of Kongdian Formation, Cangdong Sag JIAO Yuxi1, YAN Jihua1, CHEN Shiyue1, PU Xiugang2, DENG Yuan1 2017, 38 (3):  1-1.  doi: 10.7657/XJPG20170309 Abstract ( 83 )   PDF (300KB) ( 192 )   Save Regarding high natural gamma values in logging response of the sandstones in the second member of Kongdian formation in Cangdong sag, based on the core observation and thin section identification and combined with whole-rock X-ray diffraction analysis and well logging analysis, it is considered that the relatively high content of analcite and enrichment of thorium (Th) are commonly noted in the Ek2 2 tight sandstones of Cangdong sag, which leads to the high natural gamma value of the tight sandstone interval; relatively high content of white mica and enrichment of uranium (U) in some local areas in the Ek4 2 tight sandstones result in the high natural gamma value of the sandstone interval locally. The integrated use of AC logging curves, AC-GR correlation and GR-RILD correlation allows effective identification of tight sandstones with high gamma value caused by high content of analcite. Related Articles | Metrics

Improvement of Percolation Theory on Arps Production Decline Equation in Waterflooding Oilfield GAO Wenjun1, HAO Wei1, SHENG Han2, WEI Liyan3, WEN Lingxiang1, ZHENG Dengqiao1 2017, 38 (3):  1-1.  doi: 10.7657/XJPG20170310 Abstract ( 79 )   PDF (300KB) ( 205 )   Save Based on the equation of percolation theory and introduction of Эфрос’s experimental results, and combined with oil-phase relative permeability formula proposed by Willhite and Chierici, hyperbolic, exponential and harmonic decline equations and the corresponding water-phase relative permeability formula are derived. The study results show that oil-water two-phase relative permeability relationships jointly determine the production decline equations in waterflooding oilfields; in the previous studies on the percolation theory of production decline equation, the oil-phase relative permeability formula was not the industrial standard relative permeability formula which should take the outlet water saturation as an independent variable, but a pseudo relative permeability formula taking the average water saturation as an independent variable. Finally, the actual applications of the new relative permeability formulas in Sanjianfang formation in Shanshan oilfield of Tuha basin, Sartu formation in Honggang oilfield of Jinlin oilfield and the lower section of E3s1 in Maxi oilfield of Dagang oilfield show that the actual production is basically the same as the results obtained from oil and gas relative permeability formulas, which could be a reference for the study on production declines in other oilfields. Related Articles | Metrics

Optimization of Successive Development Methods of Inclined Reservoirs at Late Stage of Steam Flooding: A Case Study from Block Qi 40 in Western Sag of Liaohe Rifted Basin WANG Lili1, LIU Tao2, CAI Yuchuan3 2017, 38 (3):  1-1.  doi: 10.7657/XJPG20170311 Abstract ( 74 )   PDF (300KB) ( 153 )   Save High dip-angle(>10°) oil area in the Block Qi 40, located in the middle-southern part of the western slope in the Western sag of Liaohe rifted basin accounts for a large proportion of the steam flooding pilot areas. The high dip-angle oil area has entered the late development stage, which is characterized by continuous decline of oil production and rising production cost, so that to explore effective successive development method at the late steam drive stage for inclined reservoirs and to further enhance oil recovery have theoretical and practical significance. 4 typical well groups are selected in the high-dip angle area of western Qi 40 block, and 3D geological model and numerical model are established by using Petrel and STARS softwares, respectively, then study on optimization of successive development methods at the late steam flooding stage is carried out. Numerical simulation result shows that the producing degree of Lian I oil member is relatively high; that of Lian II oil member is relatively low with the residual oil saturation higher than 60%, and small differences exist in residual oil distributions at the high and low positions of the structure. According to the characteristics of residual oil distributions in Lian I and Lian II oil members, it is considered that separate layer steam injection technology can be used and the oil recovery factor by the technology can increase by 4.0%. The optimization result of the successive development methods at the late steam flooding stage for the inclined reservoirs in the Block Qi 40 shows that the oil recovery improved by intermittent steam flooding is the highest, reaching 5.2%; that improved by continuous steam flooding is 4.6%; those improved by alternate steam-water flooding and steam-air combination flooding are 1.8% and 3.2%, respectively. The producing degree by intermittent steam flooding is larger than those by continuous steam flooding in LianⅠoil member; the cumulative oil-steam ratio by intermittent steam flooding is higher than those by steam-air combination flooding and alternate steam-water flooding. Therefore, it is suggested that intermittent steam flooding should be the optimal successive development method at the late steam flooding stage. Related Articles | Metrics

Optimization of Volcanic Gas Reservoir Development Program Based on the Improved AHP-Entropy Weight Method and TOPSIS MA Xu1, YANG Shuangchun1, LI Bingfan2, PAN Yi1, MA Peimin3 2017, 38 (3):  1-1.  doi: 10.7657/XJPG20170312 Abstract ( 45 )   PDF (300KB) ( 94 )   Save How to choose the optimal program for volcanic gas reservoir development economically is an urgent problem to be solved. According to the construction principle of the indexes of volcanic gas reservoir development program optimization, 7 optimum indexes of development program are determined. By using the improved analytical hierarchy process (AHP) and combined with entropy weight method and the technique for order preference by similarity to ideal solution（TOPSIS), an improved AHP-entropy weight & TOPSIS-based model for volcanic gas reservoir development program optimization is established and its validity has been verified by a case study of optimization for 8 volcanic gas reservoir development programs in a block of Songliao basin. The results show that the approximation degrees of each program are 0.2947, 0.5041, 0.6798, 0.7675, 0.3165, 0.6407, 0.6213 and 0.2546, respectively. Based on the optimal selection principle, it is considered that the optimal solution is the program No.8. The optimization result could provide references for decision making in oilfields, which has some practical and theoretical significance. Related Articles | Metrics

Experimental Study on Variable Flow Resistance during Polymer Flooding in Vertically Heterogeneous Reservoirs LIU Zheyu1, LI Yiqiang1, GAO Wenbing1, XUE Xinsheng2, WANG Shanshan2, LI Xiaoxu1 2017, 38 (3):  1-1.  doi: 10.7657/XJPG20170313 Abstract ( 58 )   PDF (300KB) ( 108 )   Save Good application results of field polymer flooding test have been achieved in many oil fields, but “profile reversion” often occurs during polymer flooding process and the conventional theory of alternate polymer injection to control profile reversion is not suitable for vertically heterogeneous reservoir development. Starting with resistivity calculation of oil-water two-phase flows, this paper studies the profile reversion mechanism and its discriminant method, discusses the EOR mechanism of alternate polymer injection during general oilfield development and determines the limits of permeability contrast applicable for polymer flooding. The study result shows that the injection volume corresponding to the extreme points of fluidity in each layer is just the point where the injection profile reversion occurs during polymer flooding; when the vertically heterogeneous reservoirs are developed generally, liquid absorption amounts in low-permeability layers are not significantly improved by alternate polymer injection, whereas the processes of oil aggregation and oil bank forming can enhance oil recovery; when the permeability contrast is higher than 4 in the vertically heterogeneous reservoirs, the single-stage polymer flooding can’t get the optimal development effect, the injection profile should be modified and then polymer flooding can be carried out again to improve the oil recovery percent of reserves. Related Articles | Metrics

Analysis on Data Fitting of Hydraulic Test for Formation Fracture Pressure YANG Minghe1, SUN Ting1, YANG Hu2, CHENG Weifeng2, WEN Qianbin2, SHI Jiangang2 2017, 38 (3):  1-1.  doi: 10.7657/XJPG20170314 Abstract ( 62 )   PDF (300KB) ( 176 )   Save Hydraulic test method is an effective way to obtain formation fracture pressure. But the actual hydraulic test curve and the ideal hydraulic test curve are very different, so it is difficult to determine the formation leakage pressure directly from the actual hydraulic test curve. In order to effectively solve this problem, starting from the comparison of the characteristics of ideal hydraulic test curve and the actual one, and based on the similar geometric features between the ideal hydraulic test curve and the underdamping vibration equation with the natural frequency of π/2 and the damping coefficient of 1.00, the paper proposes a method to fit the hydraulic test data by using the underdamping vibration equation to determine the leakage pressure, which could transform the problem of determining the leakage pressure based on the actual test curve into the solving of the initial amplitude of the underdamping vibration equation. Through the analysis on reconstruction of the original hydraulic test data and the reasonable setting of the initial values and the constraint conditions of the fitting equation parameters, the difference of the order of magnitude among test data is effectively eliminated and the stability of the fitting is improved. The case analysis shows that this method provides a scientific basis for formation fracture pressure determination by using the actual hydraulic test curves. Related Articles | Metrics

Establishment and Application of A New Combined Solution Model for Water Cut Prediction LIU Peng1, LIU Pengcheng1, WANG Wenhuan2, XIA Jing2, JIAO Yuwei2, LI Baozhu2 2017, 38 (3):  1-1.  doi: 10.7657/XJPG20170315 Abstract ( 75 )   PDF (300KB) ( 169 )   Save Production prediction model and water drive type curves are two important methods in reservoir engineering analysis which are generally applied in oilfield development index prediction. But both the two methods have some limitations—production prediction model can’t be used to forecast water cut, and water drive type curve can’t be used to predict the changes of development indexes with time. Based on the feature analysis of Morgan-Mercer-Flodin(MMF) growth model, this paper derived the Hu-Chen model, simplified the process of parameter solving and established a combined solution model for water cut prediction in oilfields, which could overcome the deficiencies of the original two methods. The comparison of the actual development data with the results predicted by the model showed that the relatively high prediction accuracy of the model could meet the demand of production performance analysis, which could be a guidance for oilfield development plan making and adjustment. Related Articles | Metrics

Using Seismic Data to Predict Formation Pressure in Piedmont Structures at the Southern Margin of Junggar Basin YANG Hu1, ZHOU Penggao2, SUN Weiguo1, SHI Jiangang1, CHEN Weifeng1 2017, 38 (3):  1-1.  doi: 10.7657/XJPG20170316 Abstract ( 40 )   PDF (300KB) ( 54 )   Save The exploration degree at the southern margin of Junggar basin is very low and the calculation accuracy of formation pressure with logging data is not satisfying, especially for pressure prediction of undrilled formations in deep piedmont structures. Therefore, taking Xihu anticline?Dushanzi anticline in Sikeshu sag as an example, 2D interval velocity is obtained on the basis of logging constraint inversion of the 2D seismic data and the seismic interval velocities are effectively extracted in the 2 ultra?deep wells such as Dushan 1 and Xihu 1. A 2D formation pressure model is established by using spatial interpolation algorithm and formation pressures in individual wells, then formation pressures in regional spaces can be calculated based on the 2D interval velocity. The spatial distribution of formation pressure is obtained through visualized description and analysis. The comparison of the results predicted by the model with the field testing pressures shows that the prediction accuracy is higher than 85%. The seismic?logging combination method to forecast pressures in deep and complex formations could provide scientific basis for well bore structure design, safe drilling fluid density window determination and efficient drilling operation. Related Articles | Metrics

Using Potential Gas Production Efficiency Index to Predict Favorable Areas for Coalbed Methane Development in Shizhuang Block, Qinshui Basin WU Jian1,2, JIANG Shanyu3, ZHANG Shouren1,2, KANG Yongshang3, WANG Jin3 2017, 38 (3):  1-1.  doi: 10.7657/XJPG20170317 Abstract ( 74 )   PDF (300KB) ( 176 )   Save Coalbed methane(CBM) development in Shizhuang block of Qinshui basin is in the early stage, so detailed study on coal seams and prediction of favorable development areas should be very important for further well placement. Based on the analysis of No.3 coal seam features in Shizhang block, a new set of quantitative characterization methods for CBM reservoirs is presented, that is to select gas content, thickness, permeability and adsorption time as characterization parameters, use coal reservoir gas potential, geological gas production potential and potential gas production efficiency index to reflect resource abundance, gas production potential and potential gas production efficiency, respectively, and predict favorable areas for CBM development based on the potential gas production efficiency index. The study shows that No.3 coal seam in Shizhuang block has high resource abundance and great development potential. The potential gas production efficiency indexes are relatively high in the east and middle-south parts of the block, which should be the favorable areas for CBM development. The prediction results well match with the field pumping and producing efficiency, indicating that the method using potential gas production efficiency index to predict favorable CBM areas are reliable and feasible, which has great significance for favorable CBM area optimization. Related Articles | Metrics

Application of Improved Productivity Simulation Method in Determination of the Lower Limits of Reservoir Physical Properties in Moxi District of Anyue Gas Field WANG Lu1, YANG Shenglai1, XU Wei2, MENG Zhan1, HAN Wei1, QIAN Kun1 2017, 38 (3):  1-1.  doi: 10.7657/XJPG20170318 Abstract ( 53 )   PDF (300KB) ( 126 )   Save During the process of determination of the lower limits of gas reservoir physical properties with conventional productivity simulation method, the well producing pressure differential is approximately set as the experimental pressure differential for productivity simulation. However, the core size and single well control area are quite different, resulting in the fluid flow rate at core outlet?end not equal to that at wellbore end, leading to relatively large error in predicted results. Therefore, the conventional productivity simulation method should be improved. Similarity transformation of pressure differential is added before production similarity conversion, based on which experimental pressure differential is set to guarantee the equal fluid flow rate. The improved productivity simulation method is used to determine the lower limits of reservoir physical properties in Moxi district of An’yue gas field. The result shows that the lower limits of porosity and permeability determined by the improved productivity simulation method are 2.74% and 0.015 mD, respectively when the producing pressure differential is 6 MPa and the net pay thickness is 40 m in gas wells; while the lower limits of porosity and permeability determined by the conventional productivity simulation method are 2.42% and 0.011 mD, respectively, which is slightly lower than those determined by the improved method. The lower limits of reservoir physical properties determined by the improved productivity simulation method are more accurate. Related Articles | Metrics

Using Well Production Performance to Identify Cave-Cleft Bodies in Fractured-Vuggy Carbonate Reservoirs: A Case Study of Ha-6 Well Block in Halahatang Oilfield WANG Ping, PAN Wenqing, LI Shiyin, Liu Zhiliang, He Jun, Ma Hui 2017, 38 (3):  1-1.  doi: 10.7657/XJPG20170319 Abstract ( 71 )   PDF (300KB) ( 149 )   Save Taking Ha-6 well block as an example, based on the study of reservoir distribution and spatial relationship of oil and water in the study area, this paper analyzes the development features of producing wells, establishes 3 patterns of oil and water distribution in cave-cleft bodies which can be identified from single wells—separate oil and bottom/edge water connection pattern, separate water and bottom/edge water connection pattern and composite fracture connection pattern, and demonstrates the causes of the 3 patterns and the production characteristics. The paper also presents 3 performance analysis methods to identify cave-cleft bodies, i.e. production test data analysis method, waterflooding type curve analysis method and elastic productivity analysis method, and demonstrates the correspongding identification methods applicable for each cave-cleft body. Combined with the principle of planar distribution area determination for cave-cleft bodies, 3 types of cave-cleft bodies are identified in the study area. Related Articles | Metrics

Application of Diffracted-Wave Separation Imaging Technology in Fracture Identification LI Xiaofeng1, KONG Xue2, LIN Juan1 2017, 38 (3):  1-1.  doi: 10.7657/XJPG20170320 Abstract ( 54 )   PDF (300KB) ( 65 )   Save Fractures as the important oil-gas accumulation spaces and migration pathways control the formation and distribution of oil and gas reservoirs. Accurate understanding of the distribution of underground fracture systems is critical for petroleum exploration and further oil and gas field development. Diffracted waves are the seismic responses of small-sized geologic discontinuities such as faults and fractures etc. According to the differences of event shapes between the diffracted wave and reflected wave on the plane wave record, and using diffracted-wave separation imaging technique based on plane wave prediction, the diffracted wave field is extracted from the seismic record and imaged separately. Thus the identification accuracy of small-sized structures is improved. The numerical model and actual application result show that the diffracted-wave separation imaging technology can characterize breakpoints more clearly, which could be guidance for fracture interpretation. Related Articles | Metrics

Application of Resistivity Inversion Technique in Evaluation of Saline Water Flooded Zones XIE Yingfeng1, SHEN Huilin1, HE Shenglin2, WANG Lijuan2, DING Lei2, SHI Anping1 2017, 38 (3):  1-1.  doi: 10.7657/XJPG20170321 Abstract ( 83 )   PDF (300KB) ( 193 )   Save The resistivity of the water flooded zone decreases significantly after saline water flooding occurs in the oil zone. How to accurately identify the water flooded level is critical to evaluate the water flooded zones. The resistivities of oil-saturated and water-saturated zones can be obtained from the inversion of variable multiple material balance model. In the study area, the resistivity value of the water flooded zone falls between those of oil-saturated and water-saturated zones, and the lower the water flooded level is, the closer the formation resistivity goes to that of the oil-saturated zone; on the contrary, the higher the water flooded level is, the closer it goes to that of the water-saturated zone. The change rates relative to the resistivities of oil-saturated and water-saturated zones are used to establish a detailed interpretation chart for water flooded zone and quantitative classification standards for water flooded level. The actual application shows that the interpretation accuracy of saline water flooded zones has reached 88.8% and the resistivity inversion technology lays a foundation for logging evaluation of saline water flooded zones in Weizhou oilfield. Related Articles | Metrics