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01 June 2020, Volume 41 Issue 3 Previous Issue    Next Issue

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OIL AND GAS EXPLORATION

Genesis and Identification of Low Resistivity of Chang 2 Oil Layer in Heshui Area, Ordos Basin PAN Yiwen, ZUO Xiaohuan, ZHANG Shitao, ZHANG Yaohua 2020, 41 (3):  253-260.  doi: 10.7657/XJPG20200301 Abstract ( 507 )   HTML ( 26 )   PDF (5264KB) ( 365 )   Save In order to determine the genesis of low resistivity of Chang 2 oil layer in Heshui area of Ordos basin, the paper analyzes the data of scanning electron microscope, casting thin section, mercury injection experiment, grain size, porosity and water quality. The results show that the low resistivity of the oil layer is attributed to high salinity of formation water, complex pore structure and high content of irreducible water. The high salinity of formation water is mainly caused by atmospheric precipitation which brings the ions from weathering and denudation of the overlying strata into the formation; CO2 carried by atmospheric precipitation reacts with feldspar in the formation and then kaolinite forms. The kaolinite with unsaturated electrical properties can adsorb cation and the cation exchange quantity increases, causing the enhancement of kaolinite additional conductivity. The metal ions such as K + and Al 3+ in medium are absorbed by smectite, which results in the rearrangement of the crystal and the substitution of isomorphism, leading to the low resistivity of the reservoir. In view of the characteristics of the oil layer in the study area, the paper proposes that a crossplot of resistivity and thickness can be used to identify low-resistivity oil layers, and to determine the upper and lower limits of each factor in the low-resistance oil layer, and establishes a chart to identify low-resistance oil layers for Chang 2 member with the coincidence rate between the identification result and the oil test result being more than 80%. Figures and Tables | References | Related Articles | Metrics

Division of Methane Weathering Zones in the Middle and Lower Jurassic Coal Seams of Santanghu Basin WANG Qiong, YANG Shuguang, WANG Gang, XU Hao, REN Pengfei, DONG Wenyang 2020, 41 (3):  261-268.  doi: 10.7657/XJPG20200302 Abstract ( 423 )   HTML ( 9 )   PDF (1788KB) ( 550 )   Save Based on the gas contents and main gas components of the middle and low rank coal seams in the Santanghu basin, and combined with the structure, sedimentation and hydrogeological characteristics of the basin, the methane weathering zones in the coal seams in Hanshuiquan sag and Tiaohu sag are divided, and the methane weathering zones in the coal seams of the Kumusu sag, Malang sag, Naomaohu sag and Suluke sag are predicted. The results show that the methane weathering zones in Santanghu basin are 400-1 000 m deep. The methane weathering zone in the northern part of the basin is shallower than that in the southern part due to the influence of the thrust uplift zone in the northeastern in Santanghu basin. The sedimentary environments of the coal seams of the deep-lake-semi-deep lake facies and the braided river delta facies in Naomaohu sag, Malang sag and Tiaohu sag in the eastern Santanghu basin are better than those of the fan delta facies in Hanshuiquan sag and Kumusu sag in the western Santanghu basin, causing the methane weathering zone in the eastern basin generally shallower than that in the western basin. The methane weathering zones representing open, locally retained hydrogeological units in Tiaohu sag and Malang sag are shallower than those representing close, weak runoff hydrogeological units in other sags. It is preliminarily predicted that the northern Malang sag is the target area for further coalbed methane exploration and development, and the northern Tiaohu sag is the target area for exploration and development of the coal measure gas. Figures and Tables | References | Related Articles | Metrics

Comprehensive Prediction Model of Total Gas Content in the Shale of Yanchang Formation in Yanchang Petroleum Exploration Area DENG Changsheng, ZHANG Yi, XIE Xiaofei, MI Weiwei, QIANG Juan, SONG Jiaxuan 2020, 41 (3):  269-277.  doi: 10.7657/XJPG20200303 Abstract ( 356 )   HTML ( 16 )   PDF (655KB) ( 337 )   Save Based on isothermal adsorption experiments of shale samples, the content of adsorbed gas in the shale of Yanchang formation is calculated, and the contents of free gas and dissolved gas in the shale of Yanchang formation are calculated by establishing formulas and logging interpretation. The calculation results show that the total gas content of the shale of Yanchang formation in Yanchang petroleum exploration area is 2.25~5.08 m 3/t, among which the content of the adsorbed gas is 1.75~4.21 m 3/t, the free gas content is 0.20~0.60 m 3/t, the dissolved gas content is 0.05~0.52 m 3/t. Based on the analysis of the correlation between shale gas in different occurrence states and geological factors, it is considered that the content of the adsorbed gas is mainly controlled by temperature, pressure, TOC and water saturation, the content of the free gas is mainly controlled by porosity and gas saturation, and the content of the dissolved gas is mainly constrained by residual oil content, temperature, pressure and relative densities of natural gas and crude oil. A comprehensive prediction model of total shale gas content in different occurrence states is established for Yanchang petroleum exploration area. The measured values of the total shale gas content obtained with in-situ desorption method are used to verify the comprehensive prediction model and the results show that the model is highly reliable. Figures and Tables | References | Related Articles | Metrics

Reservoir Characteristics and Sensitivity Evaluation of Chang 23 in N Area of Xifeng Oilfield HE Hui, LI Junjian, QI Zhao, XU Zhongyi, LIU Meirong, ZHU Yushuang 2020, 41 (3):  278-287.  doi: 10.7657/XJPG20200304 Abstract ( 352 )   HTML ( 7 )   PDF (2616KB) ( 358 )   Save Based on the analysis oF physical property testing, cast thin sections, scanning electron microscope and high pressure mercury intrusion for the Chang 23 low-permeability sandstone reservoir in N area of Xifeng oilfield, the paper describes the characteristics of the reservoir, classifies the reservoir according to petrologic features, physical properties and pore throat characteristics, evaluates the reservoir sensitivities and analyzes their influencing factors. The study results show that the Chang 23 reservoir in the N area of Xifeng oilfield is dominated by fine-grained feldspar lithic sandstone. The pore types are mainly intergranular pores and feldspar dissolved pores. The average porosity and permeability of the reservoir are 16.4% and 13.5 mD, respectively, which indicates the reservoir belongs to medium—low porosity, low permeability reservoirs. The reservoir can be divided into three types: the physical property and pore throat structure of Type Ⅰ reservoir are the best, and those of Type Ⅱ and Type Ⅲ reservoirs become worse and worse. The reservoir in the study area is featured with moderate-weak velocity sensitivity, weak water sensitivity, moderate-weak salt sensitivity, moderate acid sensitivity, strong alkali sensitivity and moderate-strong pressure sensitivity. The sensitivities of the reservoir in the study area are influenced by clay minerals, partial clastic grains and pore throat structures. The velocity sensitivity of the reservoir is mainly related to kaolinite content, and water and salt sensitivities related to illite content and occurrence. The acid sensitivity is influenced by both chlorite and ferrodolomite contents, strong alkali sensitivity results from high contents of feldspar and quartz and pressure sensitivity is the result of the deformation of pore throats. The clay content, pore throat structure, physical property and sensitivity of the three types of reservoir are different. During the process of oilfield development, reservoir protection should be carried out according to the sensitivity controls and the differences of sensitivity of different reservoirs, so as to reduce the damage to reservoir. Figures and Tables | References | Related Articles | Metrics

RESERVOIR ENGINEERING

Analysis on Original Gas Saturation of Volcanic Gas Reservoir Based on NMR Experiment ZHANG Mingyu, KONG Chuixian, QI Hongyan, LI Liang, ZHOU Yang, SU Jing, JIANG Qingping 2020, 41 (3):  288-294.  doi: 10.7657/XJPG20200305 Abstract ( 319 )   HTML ( 12 )   PDF (648KB) ( 308 )   Save In order to analyze the gas saturation of the low-permeability volcanic gas reservoir in X gas field, nuclear magnetic resonance（NMR）experiments were carried out to analyze the gas saturations of 50 pieces of cores from 6 wells in the area. The results show that when the calibrated centrifugal force is 2.760 MPa in the centrifugal experiment and the lower limit of the effective flowing throat radius is 0.053 μm, the calculated movable fluid saturation agrees well with the experimental results and the field production data. When the centrifugal force is higher than 2.760 MPa, the irreducible water saturation of the core changes a little with the increase of the centrifugal force. When the centrifugal force is lower than 2.760 MPa, the movable fluid saturation is approximate to the original gas saturation of the reservoir, and the T2 value calibrated by the experiment can be considered as the T2 cutoff of the target reservoir and can be directly used to determine the original gas saturation and the original water saturation of the gas reservoir. The method of NMR T2 spectrum can be used to accurately evaluate the original gas saturation of the volcanic gas reservoir, which provides theoretical basis and technical support for logging interpretation of gas saturation in similar gas reservoirs. Figures and Tables | References | Related Articles | Metrics

Influences of the New Method of PVT Data Correction on Dynamic Prediction in Volatile Oil Reservoirs LU Kefeng, CAI Hua, DING Fang, SU Chang, SHI Meixue, LI Ning, MA Lian 2020, 41 (3):  295-301.  doi: 10.7657/XJPG20200306 Abstract ( 274 )   HTML ( 7 )   PDF (555KB) ( 336 )   Save In view of the problem that the experimental data can’t be directly used in reservoir engineering calculation due to the large amount of stock tank oil loss in the process of multiple degasification of volatile oil, this paper proposes a new method to correct the experimental data of multiple degasification by means of constant-volume depletion experimental data step by step. The new method is different from the traditional method presented by Terry and Rogers（2017）that the experimental data of single degasification are used to correct the experimental data of multiple degasification. The comparison of the two methods shows that the traditional correction method is only suitable for conventional black oil, and may produce the non-physical correction results for volatile oil. The new method considers the variation of oil content in oil tanks with pressure in the exhaust gas under the standard condition, so it is applicable to both conventional black oil and volatile oil, and the correction result of the new method is close to that from the traditional Terry and Rogers method under the condition of saturated pressure. Finally, a simple iterative method is established based on the principles of material balance and oil & gas two-phase percolation, and the influences of various experimental data on development performance are calculated and compared. The results indicate that the typical black oil experimental data can be directly used for reservoir engineering calculation; the stronger the oil volatility is, the higher the recovery factor calculated from the new method will be; for the high volatility oil in the case, the error of the crude oil recovery percent of reserves calculated from the experimental data obtained with the traditional method is as high as -13.82% when compared with the new method. Figures and Tables | References | Related Articles | Metrics

Laws and Models of Water Invasion in Kela 2 Gas Field WU Yongping, YANG Ming, LI Ming, SUN Yong, ZHANG Yongbin, WANG Hao 2020, 41 (3):  302-306.  doi: 10.7657/XJPG20190607 Abstract ( 450 )   HTML ( 15 )   PDF (1338KB) ( 489 )   Save Kela 2 gas field in Tarim basin is a massive ultra-high-pressure dry gas reservoir with the largest proved reserves in China. Since 2010, water breakthrough due to geological conditions has been found in seven wells, which brings risks to the steady production of the gas field. Therefore, it is very important to understand the laws and to identify the models of water invasion in the gas field. This paper analyzes the general characteristics of water invasion in the gas field, and determines four regions with different water invasion models. Regarding the watered-out wells in the different regions, the fracture development degree, the relationship between high-permeable zone and interlayer and the distance from high-permeable zone to edge/bottom water are analyzed and the main factors controlling water invasion in watered-out wells are identified. The main direction of incoming water is determined through fault plugging capacity evaluation, dynamic tracking well test analysis and post-casing saturation time comparison. Combined with production performance and history matching of geological model, the water invasion models are determined and the model in single well can be divided into three types such as vertical channeling and lateral invasion of bottom water, lateral invasion of edge water and invasion upwards of bottom water. Based on the numerical simulation of the gas reservoir, the water invasion models in non-watered-out wells can be predicted and a detailed development strategy is proposed to ensure the continuous and efficient development of the Kela 2 gas field. Figures and Tables | References | Related Articles | Metrics

Fuzzy-Ball Fluid Assisted Polymer Flooding to Enhance Oil Recovery in Heterogeneous Conglomerate Reservoirs WEI Panfeng, ZHENG Lihui, JI Cheng, CHEN Qilong, HUANG Ying, FAN Aibin 2020, 41 (3):  307-313.  doi: 10.7657/XJPG20200308 Abstract ( 314 )   HTML ( 5 )   PDF (1207KB) ( 320 )   Save When highly permeable pathway coexists with low permeable pathway in heterogeneous conglomerate reservoirs, it is difficult to significantly improve oil recovery by applying conventional polymer flooding. Vesicles in fuzzy-ball fluids can enter and accumulate under the low flow resistance of the highly permeable pathways, then reduces the flow resistance difference between the highly and low permeable pathways, causing displacing medium to go into the low permeable zones and then improving oil recovery. In this paper, an artificial core with the size of 45 mm×45 mm×300 mm and the permeability ranging from 200 mD to 1 200 mD was selected to simulate various flow pathways and cores with the permeability of 10–1 200 mD were connected in parallel to simulate heterogeneous reservoir. With the displacement pressure of 0.11–0.57 MPa, the difference of the oil recovery factor between highly permeable core and low permeable core ranged from 16.69% to 37.93% after waterflooding and polymer flooding, which increased with the rise of the core permeability ratio. Then 0.6 PV fuzzy-ball fluid was injected and the recovery factor of the low permeable core was 11.15%–19.97% higher than that of the highly permeable core with the displacement pressure of 33.89–39.12 MPa, indicating the displacing medium flowing into the low permeable core, and the oil recovery factor could be improved by 8.17%–11.54%. Field tests of fuzzy-ball fluids in TX well and TY well in Block Qidong-1 of Karamay oilfield were carried out and 150 m 3 and 123 m 3 fuzzy-ball fluids were injected into the two wells, respectively, and the wellhead pressures of the two wells were improved by 4.70 MPa and 1.28 MPa, respectively. After 90 days of the injection operation, the daily oil production of the two tested wells increased by 64.15% and 17.74%, respectively, and the overall watercut decreased by 7.94% and 10.91%, respectively, proving that the fuzzy-ball fluid assisted polymer flooding technology was feasible to enhance oil recovery. Figures and Tables | References | Related Articles | Metrics

Characteristics of In-Situ Stress in Sandy Conglomerate Reservoir of Badaowan Formation in District No.7, Karamay Oilfield WANG Zhenyu, LIN Botao, YU Huiyong, SHI Shanzhi, KOU Xiangrong 2020, 41 (3):  314-320.  doi: 10.7657/XJPG20200309 Abstract ( 392 )   HTML ( 15 )   PDF (1984KB) ( 288 )   Save The reservoir of Badaowan formation in District No.7 of Karamay oilfield is dominated by medium-coarse sandstone and conglomerate. The reservoir has been developed for a long time and remaining oil is widely distributed in the formation. In order to realize potential tapping in small layers and to reduce reservoir heterogeneity, separate-layer fracturing has been carried out. In the process of reservoir stimulation, some fractures penetrated interlayers and connected with water layer, resulting in poor stimulation effect. In order to understand rock mechanical characteristics and regional in-situ stress distribution, the paper establishes a 3D stress field model for the reservoir on the basis of lab core experiments and field data analysis. The stresses are almost the same in the southwestern and central part of the reservoir, the stress in the southeastern part is greatly influenced by fault and that in the southwestern part is influenced by fault gently. 5 reverse faults with large dip angle variations are developed in the study area and the stress mutation occurs at the junction of the faults, which will impact fracturing operation, therefore the operation parameters should be adjusted. The fractures in the southwestern and central reservoir extend upwards and downwards evenly. In the southeastern part of the reservoir, fractures tend to extend along the directions easily to stretch if encountering thick interlayers, so that the aquifer is connected, and fractures can easily penetrate thin interlayers. The fracture heights under the displacement of 2 m 3/min and 3 m 3/min are simulated and it is found that the fracture height under the displacement of 3 m 3/min is hard to be controlled due to the fracture’s large vertical extension and its connection with bottom water, and the fracture extension under the the displacement of 2 m 3/min can be controlled. Figures and Tables | References | Related Articles | Metrics

Dynamic Reserves Evaluation of Fractured-Cavity Reservoirs With Closed Water：A Case From Halahatang Oilfield, Tarim Basin LI Hongbo, WANG Cuili, NIU Ge, LIANG Hongtao, BU Lulu, GU Junying 2020, 41 (3):  321-325.  doi: 10.7657/XJPG20200310 Abstract ( 375 )   HTML ( 8 )   PDF (723KB) ( 353 )   Save The fractured-cavity carbonate reservoirs are characterized by strong heterogeneity, complex connectivity and non-uniform oil-water interface, which lead to the difficulties in reserves evaluation and poor development effect. Using dynamic data, the paper improves the material balance equation according to the characteristics of the fractured-cavity carbonate reservoirs with closed water, then proposes a dynamic reserves evaluation method for this kind of reservoirs by combining with the predicted static reserves. The dynamic oil reserves and the water size can be accurately calculated with the method under the conditions without oil-water contact location and measured PVT data of reservoirs. Good application effects have been gained in Halahatang oilfield, Tarim basin. Figures and Tables | References | Related Articles | Metrics

Variations of Produced Polymer Concentration for Polymer Flooding in Conglomerate Reservoirs ZHANG Defu, LYU Jianrong, TIAN Mi, ZHANG Jing 2020, 41 (3):  326-331.  doi: 10.7657/XJPG20200311 Abstract ( 276 )   HTML ( 5 )   PDF (645KB) ( 338 )   Save Over a long-term waterflooding development, the conglomerate reservoir of the lower Karamay formation in QD1 block of Karamay oilfield in Xinjiang is featured with strong heterogeneity, developed fracture and developed preferential migration pathway. But high concentration of produced polymer in producers during subsequent polymer flooding affects the polymer flooding effect. In order to understand the variations of produced polymer concentration of polymer flooding in conglomerate reservoirs, taking the reservoir characteristics and fluids in QD1 block as research objects, the paper carries out studies related to production stage classification for the polymer flooding, rising law of the produced polymer concentration, charts of the produced polymer concentration limits and the lower injection pressure limits for polymer channeling control. The results show that the production stage of polymer flooding in conglomerate reservoirs can be classified into early stage of polymer injection, peak response stage, late response stage and subsequent water flooding stage. The peak response stage generally lasts for 2 or 3 years with the maximum produced polymer concentration of 737.2 mg/L, the maximum relative produced polymer concentration of 0.550 and the concentration rising rate of 2.3; when the well spacings are 140 m and 120 m, the reasonable rise rate of the relative concentration is 2.3~6.0, the corresponding relative concentration ranges from 0.276 to 0.720 and the produced polymer concentration is 414.0~1 080.0 mg/L. The lower limits of injection pressure for polymer channeling control in wells dominated by preferential migration pathway, hydraulic fracture and fracture plus pathway are 8 MPa,10.0 MPa and 9.5 MPa, respectively. The research results can provide references for production performance adjustment and well treatment during polymer flooding in conglomerate reservoirs in this area. Figures and Tables | References | Related Articles | Metrics

Multiple Thermal Fluid Huff-Puff Mechanism Based on Discrete Wellbore Model ZHANG Na, ZHU Yuanrui, ZHU Yangwen, LI Jinpan, WEI Cuihua 2020, 41 (3):  332-336.  doi: 10.7657/XJPG20200312 Abstract ( 244 )   HTML ( 4 )   PDF (572KB) ( 253 )   Save After several cycles of multiple thermal fluid huff-puff, the oil production of onshore heavy oil reservoirs decreased significantly, and the development effect became worse. Due to the lack of understanding of the mechanism of multiple thermal fluid huff-puff, it is difficult to propose effective adjustment strategy after multiple thermal fluid huff-puff and it is necessary to further clarify the development mechanism of the multiple thermal fluid huff-puff in horizontal wells. The paper optimizes discrete wellbore models by using numerical method and analyzes multiple thermal fluid huff-puff process by comparing with hot water huff-puff. The results show that the discrete wellbore model considering the influence of variable mass flow of multiple thermal fluid and the coupling between wellbore and formation can better reflect the changes of temperature field and viscosity field of multiple thermal fluid huff-puff in horizontal wells in heavy oil reservoirs. Based on the simulation results of the multiple thermal fluid huff-puff with the discrete wellbore model, it can be found that the heated area along the horizontal well is in the shape of a “long-spoon”, and the viscosity reduction area has been expanded gradually due to gas-liquid separation. The multiple thermal fluid huff-puff technology combines multiple mechanisms such as heat-gas compound viscosity reduction, increasing sweep coefficient, gas-assisted gravity drainage and improving heat efficiency and the recovery factor has been improved. Figures and Tables | References | Related Articles | Metrics

Modified Methods of Permeability Prediction for Tight Sandstone Reservoirs ZHAO Tianyi, NING Zhengfu, CHEN Gang, TIAN Lingyu, QIAO Hui, WANG Jiwei 2020, 41 (3):  337-343.  doi: 10.7657/XJPG20200313 Abstract ( 329 )   HTML ( 8 )   PDF (1340KB) ( 380 )   Save Tight sandstone reservoir is featured with tiny pore throat and complicated pore throat structure. The available models for reservoir permeability prediction are generally used for conventional sandstone or carbonate reservoirs, which cannot get good permeability prediction results of tight sandstone reservoirs. 10 core samples of tight sandstone obtained from Chang 6–Chang 8 members in Ordos basin are selected and the mineral compositions and pore throat structures of the samples are analyzed based on experiments of mineral analysis and SEM. On the basis of high-pressure mercury injection experiment, the paper modifies the parameters for 8 typical reservoir permeability prediction models, establishes modified methods suitable for permeability prediction of tight sandstone reservoirs and carries out model optimization and adaptability evaluation. The results show that the good prediction results for tight sandstone reservoirs can be obtained from the modified Pittman model, Winland model, Dastidar model and K-T model, but the prediction results from the modified Purcell model, Swanson model, Thomeer model and W-A model are relatively poor. Figures and Tables | References | Related Articles | Metrics

A New Method to Determine Initial Production of Steam Stimulation in Offshore Heavy Oilfield ZHENG Wei, TAN Xianhong, WANG Taichao, ZHU Guojin, ZHANG Lijun 2020, 41 (3):  344-348.  doi: 10.7657/XJPG20200314 Abstract ( 335 )   HTML ( 4 )   PDF (488KB) ( 303 )   Save In view of the simple assumption and poor adaptability of the current production prediction model for steam stimulation, methods of well testing and analogy are generally used to determine the initial production of steam stimulation in offshore heavy oilfields. At present conventional well testing is carried out in offshore oilfields, which cannot directly obtain initial oil production of thermal recovery. The paper proposes a new method to determine the initial production of steam stimulation for offshore heavy oilfields, and establishes a initial production multiple prediction model for steam stimulation compared with conventional development. The results show that the production multiple at the initial steam stimulation stage is mainly affected by reservoir permeability, oil viscosity, injection intensity, steam dryness and other factors. A nonlinear prediction model among initial production multiple, reservoir parameters and injection parameters is established by using the mathematical methods of orthogonal test design and multiple regression. The prediction error of the new model is less than 5% and the reliability is high. The new method can provide basis for the accurate determination of the initial production of the offshore steam stimulation. Figures and Tables | References | Related Articles | Metrics

Study on Darcy Flow at Low Velocity in Tight Sandstone Reservoirs YUAN Yinchun, LI Min, WANG Ying, LI Chuanliang, WEI Mingjiang 2020, 41 (3):  349-354.  doi: 10.7657/XJPG20200315 Abstract ( 320 )   HTML ( 4 )   PDF (1132KB) ( 386 )   Save Darcy’s law is a classic formula to describe fluid flow in reservoir rocks, but low-velocity non-Darcy flow phenomena and the related theories raise questions about the applicability of Darcy’s law at low flow rates. The pores in the typical tight cores from Jimsar sag are various and unevenly distributed, showing a extremely fine throat-medium-large pore combination pattern. Low velocity flow experiments are carried out with high precision instruments, mineralized water and simulated oil, and a high accuracy syringe pump is used to ensure the constant flow of fluids. The Darcy’s flow velocity-pressure gradient relationship is characterized by a power relationship, and the resistance coefficient-Reynolds number relationship based on permeability is analyzed to determine the fluid flow state. The experiment results show that the pressure gradient is exponentially related to Darcy velocity, which is consistent with the analysis result of the relationship between Reynolds number and resistance coefficient. In the cores obtained from the tight reservoir in Jimsar sag, the low-velocity flow is linear flow. In addition, according to the analysis on the flux-pressure gradient curve, the low-velocity flow of single phase fluid in the core of the Jimsar tight sandstone reservoir basically accords with linear flow, and the flow behavior of the single-phase fluid in the tight sandstone is related to the property of the rock rather than fluid type. Figures and Tables | References | Related Articles | Metrics

A Method to Predict Reasonable Reserve-Production Ratio Limit for Oilfields WANG Luchun, ZHAO Xin, LI Jindong, SUN Zhijie, XUE Rui 2020, 41 (3):  355-358.  doi: 10.7657/XJPG20200316 Abstract ( 315 )   HTML ( 5 )   PDF (415KB) ( 557 )   Save In order to evaluate whether the reserve-production ratio of an oilfield is reasonable or not, according to the definition of reserve-production ratio,the relationship among production decline rate and liquid production, the relationship between production decline rate and watercut, the paper establishes the relationships between the reserve-production ratio and produced fluid, watercut rise and reserve-production equilibrium coefficient, respectively, and predicts the trends of reserve-production ratio in different development modes. Additionally, the paper establishes an annual reserve-production ratio formula under the ideal conditions and charts of rapid prediction of reasonable reserve-production ratio, divides the reserve-production ratio at the limit watercut into 4 categories including reasonable, relative reasonable, unreasonable and extremely unreasonable reserve-production ratio and then determines the reasonable reserve-production ratio. Applying this method into a block and assuming that other conditions remain unchanged, the reserve-production ratio is already negative when the watercut reaches 96.2%, indicating a relatively low reserve-production ratio. Finally, the reasonable reserve-production ratio is determined as 8.2, which provides new references for reasonable reserve-production ratio limit determination in oilfields and countermeasures for development plan adjustment based on the rationality evaluation of the current reserve-production status of oilfields. Figures and Tables | References | Related Articles | Metrics

APPLICATION OF TECHNOLOGY

Evaluation of Fracability of Volcanic Reservoir in Deep Gas Reservoirs of Wangfu Fault Depression LIU Guangyu, WANG Weiming, WANG Yanling 2020, 41 (3):  359-364.  doi: 10.7657/XJPG20200317 Abstract ( 271 )   HTML ( 6 )   PDF (538KB) ( 261 )   Save The volcanic rocks in the deep gas reservoir of Wangfu fault depression are characterized by deep burial and poor physical properties, so the conventional production methods cannot get good effects and it is need to carry out fracturing stimulation in this kind of reservoirs. Taking the volcanic rock in the deep gas reservoir in Wangfu fault depression as the research object and based on rock mechanics experiment and acoustic emission test, the fracture making ability and fracability of the reservoir are comprehensively evaluated by combining the anisotropy, brittleness, stress sensitivity, natural fracture density and acoustic emission activity of the rock. The results show that the volcanic rocks in the deep gas reservoir of Wangfu fault depression have high content of brittle minerals and high compressive strength; the elastic wave velocity of the rock varies a lot, the stress sensitivity is different and the anisotropy of natural fractures is weak; the reservoir is sensitive to fluids and the fluid fracture making ability are relatively strong when distilled water and KCl solution with the mass fraction of 15% are used. The comprehensive evaluation of reservoir fracability can provide theoretical guidance for the optimization of fracturing horizon and fracturing fluid and design of fracturing plan, meanwhile provide basis for exploration and development of the deep gas reservoirs in Wangfu fault depression. Figures and Tables | References | Related Articles | Metrics

Integrated Formation Pressure Testing by Logging and Genesis of Abnormal High Pressure in Gaoquan Anticline XU Xinniu, LI Yujing, RUAN Biao, CAO Guangfu, HUANG Hong, YANG Hu 2020, 41 (3):  365-371.  doi: 10.7657/XJPG20200318 Abstract ( 355 )   HTML ( 8 )   PDF (778KB) ( 393 )   Save There are many formation pressure testing methods by logging at home and abroad, but most of them are based on the undercompaction theory and limited to a single lithology of formations. Especially for the deep piedmont structures in the margin of the basin, logging interpretation with a single parameter will lead to large errors in formation pressure determination, and cannot give an explanation about more abnormal pressure mechanisms other than sedimentary compaction mechanism. Therefore, the logging parameters related to various abnormal high pressure mechanisms are comprehensively interpreted, a multi-parameter model and several testing methods suitable for complex piedmont structures are established for formation pressure testing by logging and the formation pressure profiles of Well Gaotan-1 in Gaoquan anticline in the southern margin of Junggar basin are evaluated in detail. The calculated results are in good agreement with the measured data and the relative error is less than 3.00%. Meanwhile, based on the mechanical relationship of the original sedimentary loading-unloading processes, the forming mechanism of the abnormal high pressure in the deep strata of Gaoquan anticline is determined by using this multiple logging parameter analysis method. Figures and Tables | References | Related Articles | Metrics

Evaluation of Volume Refracturing Effect in Vertical Wells in Existing Blocks ZHANG Anshun, YANG Zhengming, LI Xiaoshan, XIA Debin, ZHANG Yapu, ZHAO Xinli 2020, 41 (3):  372-378.  doi: 10.7657/XJPG20200319 Abstract ( 326 )   HTML ( 13 )   PDF (2374KB) ( 339 )   Save Based on the concepts of volume fracturing in horizontal wells, field tests of volume refracturing in vertical wells have been carried out in each oilfields of PetroChina. Because the geostress fields in vertical wells in existing blocks are complex and it is impossible to evaluate fracturing effect by using microseismic monitoring technique on a scale, this paper establishes a fracturing effect evaluation method based on well test data, flowback data and production data. The evaluation model proposed in this paper considers the true nonlinear flow in formations, and uses the product of nonlinear factor and absolute permeability to represent apparent formation permeability. The stimulated area can be classified into several secondary fracture areas according to fracture network complexity. The differences among different secondary areas on the double logarithmic curves are analyzed. Sensitivity analysis shows that the length of major fracture has a few impacts on later production, so that the major fracture length can be used as a basic parameter to do production match. Taking a vertical well in an existing block in Changqing oilfiled as a case, it is considered that premature shut-in pressure survey will result in deviations, there will be some risks of water breakthrough during volume refracturing in vertical wells. In the flowback and production stages, the effect of volume refracturing becomes poorer and poorer, which is more obvious in the core area. During the production stage, the permeability in the core area is only 13.3% of that in the flowback stage and the stimulated area in this stage is 30.0% of that in the flowback stage. Figures and Tables | References | Related Articles | Metrics