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01 June 2023, Volume 44 Issue 3 Previous Issue    Next Issue

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OIL AND GAS EXPLORATION

Exploration Progress and Potential Evaluation of Deep Oil and Gas in Turpan-Hami Exploration Area ZHI Dongming, LI Jianzhong, CHEN Xuan, YANG Fan, LIU Juntian, LIN Lin 2023, 44 (3):  253-264.  doi: 10.7657/XJPG20230301 Abstract ( 319 )   HTML ( 537 )   PDF (2522KB) ( 256 )   Save To realize the shift of oil and gas exploration from shallow-middle to deep strata, and from conventional to unconventional resources, and then to promote the exploration of deep oil and gas resources in the Turpan-Hami exploration area, the tectonic-lithofacies palaeogeographical evolution of Turpan-Hami basin, Santanghu basin, and Zhundong block of Junggar basin were analyzed, the characteristics and exploration potential of the petroleum systems in these basins were evaluated, the main exploration targets were determined, and the fields for strategic breakthrough were selected. In the Carboniferous-Permian period, the Turpan-Hami exploration area was a unified sedimentary basin with similar sedimentary environments and structures. In the Triassic-Jurassic period, the study area was separated into several independent foreland basins. With the tectonic-lithofacies palaeogeographical evolution, three sets of source rocks (marine-transitional facies of Carboniferous, lacustrine facies of Permian, and lacustrine-coal measure of Jurassic) were formed, contributing to three major petroleum systems. The change in exploration ideas has promoted significant progress in petroleum exploration in deep strata. Significant breakthroughs have been made in the exploration of Shiqiantan formation marine clastic oil and gas reservoirs, Permian shale oil reservoirs and conventional sandstone oil reservoirs in the Zhundong block, and the Middle-Lower Jurassic large-scale tight sandstone gas reservoirs in the Turpan-Hami basin, which enables the discovery of large-scale high-quality reserves and the orderly succession of strategic resources. Future exploration should be carried out at three levels: strategic preparation, strategic breakthrough, and strategic implementation, with a focus on 10 favorable directions. Figures and Tables | References | Related Articles | Metrics

Sequence Division of Shiqiantan Formation in Shiqiantan Sag on Eastern Uplift of Junggar Basin KANG Jilun, FU Guobin, HAN Cheng, LIANG Hui, MA Qiang, LIANG Guibin, CHEN Gaochao 2023, 44 (3):  265-276.  doi: 10.7657/XJPG20230302 Abstract ( 201 )   HTML ( 506 )   PDF (27313KB) ( 103 )   Save In order to establish a standard section of the Upper Carboniferous Shiqiantan formation in the Shiqiantan sag on the eastern uplift of the Junggar basin, and to provide a basis for the division and correlation of the subsurface strata and for the oil and gas exploration in the sag, field survey was carried out. By using geological coastean, and through comprehensive analysis on lithological characteristics, sedimentary formations, contact relationships, marker beds, and paleontological fossils, the sequence division, sedimentary facies restoration, and regional stratigraphic correlation were completed for the Shiqiantan formation. The Shiqiantan formation underwent the deposition of alluvial fan (fan delta), pre-fan lake and bay lagoon, forming three transgression-retrogradation sequences. The Shiqiantan formation can be divided into three members. The lower member is composed of conglomerate and sandy conglomerate intercalated with sandstone and siltstone in the lower part, medium-fine grained conglomerate, graywacke, and interbeds of mudstone and silty mudstone in the middle part, and silty mudstone and mudstone intercalated with sandstone and siltstone in the upper part. The middle member is composed of conglomerate, pebbly sandstone and sandstone intercalated with siltstone in the lower part, and calcareous silty mudstone, mudstone, siltstone and argillaceous limestone in the upper part. The upper member is composed of conglomerate, sandstone and interbeds of siltstone and silty mudstone in the lower part, purple-brown and brick-red mudstone and argillaceous siltstone intercalated with gravel-bearing gritstone and conglomerate in the middle part, and dark grey mudstone and silty mudstone intercalated with limestone in the upper part. Macroscopically, the lower member, middle member, and the upper part of the upper member are dark grey, and the lower part of the upper member is light brown to brick-red; all members are normally graded. The dark mudstones of pre-fan swamp-bay lagoon facies are favorable source rocks, while the sandstones and conglomerates of mid-fan and fan-apex facies are reservoir rocks. The good source-reservoir assemblage suggests favorable petroleum geology conditions. Figures and Tables | References | Related Articles | Metrics

Source Rock Evaluation and Oil-Source Correlation for Middle-Lower Jurassic Tight Oil in Shengbei Subsag, Turpan-Hami Basin LIU Feng, ZHAO Hongjing, JIN Ying, GAN Yingxing, ZENG Yan, WEN Wangbiao, XU Guifang 2023, 44 (3):  277-288.  doi: 10.7657/XJPG20230303 Abstract ( 189 )   HTML ( 502 )   PDF (1407KB) ( 113 )   Save 22 oil and gas layers in the tight sandstones below the Xishanyao formation were interpreted in the risky exploration Well Qintan-1 in the Shengbei subsag, Turpan-Hami basin. It is necessary to evaluate the encountered source rocks and determine the tight oil source. The source rocks in the Xishanyao formation are non-or poor source rocks in most intervals near Well Taican-2, except the 4 700-4 900 m interval, and are moderate-good source rocks in Well Qintan-1 in the subsag. The source rocks in the Sangonghe formation are moderate to good. The organic matters in the Middle-Lower Jurassic are generally Type Ⅱ2-Ⅲ. The Xishanyao formation source rocks are mature, while the Sangonghe formation and Badaowan formation source rocks are highly mature. The carbon number of the paraffins in the soluble organic matters in source rocks distributes in a wide range, and the C27-C28-C29 αααR sterane shows a reverse “L” configuration, indicating a hybrid organic matters mainly sourced from terrestrial higher plants. The organic matter of Xishanyao formation has a low gammacerane content and a relatively high pristane-phytane ratio (Pr/Ph), corresponding to a weak oxidation-weak reduction sedimentary environment with relatively low salinity. The organic matter of Sangonghe formation and Badaowan formation have low Pr/Ph and high gammacerane content, showing a strong reduction sedimentary environment with high salinity. β-carotane is developed in the entire Sangonghe formation, and is quite abundant in some intervals, with the content equivalent to that of the main peak n-alkanes, indicating the contribution of halophilic bacteria and a reducing water environment in these intervals. According to the parameters such as C27/C29 αααR sterane, Pr/Ph, C19+20/C23+24 tricyclic terpane, C24 tetracyclic terpane/C26 tricyclic terpane, rearranged hopane and β-carotane, it can be inferred that the crude oil in the Sangonghe formation came from the source rocks of the same formation; the crude oil at the bottom of the Xishanyao formation originated from the Sangonghe formation source rocks enriched in β-carotane and underwent secondary migration, and the oil sand extracts from the upper and middle members of the Xishanyao formation are related to the source rocks in the Xishanyao formation. Figures and Tables | References | Related Articles | Metrics

Diagenesis and Pore Evolution of Tight Reservoirs of Sanjianfang Formation in Shengbei Subsag ZHOU Gang, CHENG Tian, LI Jie, CHEN Anqing, LI Fuxiang, XU Hui, XU Shenglin 2023, 44 (3):  289-298.  doi: 10.7657/XJPG20230304 Abstract ( 176 )   HTML ( 19 )   PDF (5123KB) ( 92 )   Save The Sanjianfang formation in the Shengbei subsag of the Tabei sag in the Turpan-Hami basin is rich in oil and gas resources. However, the sandstone reservoirs in this formation are tight and heterogeneous, which hinders the exploration and development of oil and gas. Based on core and thin-section observations, electron microscopy scanning, and high-pressure mercury injection tests, the diagenetic processes and pore evolution of the tight sandstone reservoirs of the Middle Jurassic Sanjianfang formation in the Shengbei subsag were studied. The results show that the tight sandstone reservoirs of the Sanjianfang formation are mainly composed of feldspathic litharenite and lithic sandstone, and dominantly contain secondary pores, with an average porosity of 6.44% and an average permeability of 0.18 mD, indicating low-porosity and low-permeability reservoirs. The diagenetic evolution process includes compaction-authigenic clay mineral cementation, chlorite-rimming cementation-phase-Ⅰ quartz enlargement and feldspar dissolution-albitization-rimmed chlorite cementation-carbonate cementation-feldspar dissolution-kaolinite illitization. The sandstone is currently in phase B of the middle diagenetic stage. The average initial porosity of the Sanjianfang formation sandstones is 34.66%. The average reduction in porosity is 14.05% due to compaction and 0.50% due to the cementation in phase A of the early diagenetic stage, 3.21% due to compaction and 0.75% due to cementation in phase B of the early diagenetic stage, 7.02% due to compaction and 4.26% due to cementation in phase A of the middle diagenetic stage, and 1.08% due to compaction and 0.75% due to cementation in phase B of the middle diagenetic stage. The dissolution process in phase A of the middle diagenetic stage is crucial to the increase in porosity, with an average increase of 3.38%. Figures and Tables | References | Related Articles | Metrics

Microscopic Characteristics of Fine-Grained Reservoirs in Lucaogou Formation, Santanghu Basin QIN Enpeng, ZHANG Junying, ZHANG Shengbing, LIU Juntian, ZHANG Xiaoqin, CHEN Yonghui 2023, 44 (3):  299-306.  doi: 10.7657/XJPG20230305 Abstract ( 165 )   HTML ( 16 )   PDF (12481KB) ( 73 )   Save The fine-grained rocks in volcanic-active strata are characterized by complex composition, tight cementation, and strong heterogeneity. The concept and classification methods of fine-grained rocks were systematically reviewed. Combined with rock thin section identification, whole-rock X-ray diffraction (XRD) experiment, and scanning electron microscope-energy dispersive spectroscopy (SEM-EDS) experiment, a method for studying the microscopic characteristics of fine-grained reservoirs was established. By using this method, the petrological characteristics, and types and genesis of reservoir spaces of the fine-grained rocks in the Lucaogou formation of the Santanghu basin were analyzed. The results show that the fine-grained reservoirs in the Lucaogou formation are mainly composed of fine-grained carbonate rocks and fine-grained volcanoclastic rocks. The reservoir space is mainly contributed by fractures and pores, and the fractures are dominantly structural fractures and interbed. Fine-grained volcanoclastic rocks generally have volcanic dust solution pores, rock debris solution pores, crystal debris solution pores, and calcite vein solution pores. Micro-nanopores are relatively developed in fine-grained carbonate rocks, including dolomite intercrystalline pores, calcite intercrystalline pores, and clay mineral intercrystalline pores. The enrichment of volcanic material provides material basis for high-quality fine-grained reservoirs in volcanic-active strata, and the alternation of various laminae in fine-grained reservoirs is conducive to the formation of micropores and microfractures. Figures and Tables | References | Related Articles | Metrics

Geological Evaluation and Favorable Areas of Underground Coal Gasification in Santanghu Basin WANG Xinggang, FAN Tanguang, JIAO Lixin, DONG Zhen, CAO Zhixiong, HAN Bo 2023, 44 (3):  307-313.  doi: 10.7657/XJPG20230306 Abstract ( 195 )   HTML ( 12 )   PDF (671KB) ( 132 )   Save Underground coal gasification (UCG) is a revolution in traditional coal mining technology, and the site selection of underground coal gasifier is a prerequisite for a successful UCG project. The geological conditions of UCG of the Jurassic Xishanyao formation in the Santanghu basin were evaluated based on the analysis of coalseam thickness, burial depth of coalseam, coal petrology and quality, geologic structure, roof lithology of coalseam and hydrogeological conditions. The results show that the Xishanyao coalseam is featured with a low coal rank, high ash and volatile matter contents, moderate dip angle and burial depth, and roof lithology consisting of mudstone, siltstone, and sandstone with underdeveloped faults, and good-quality water barriers, which provide favorable geological conditions for UCG. Furthermore, 18 indexes (e.g. structural complexity, burial depth, and coal-seam thickness and so on) for evaluating favorable areas of UCG were identified depending upon the geological characteristics of the Santanghu basin, and a multi-level mathematical model was established for evaluating UCG in the basin. According to UCG potential, the whole basin is divided into TypeⅠ, Type Ⅱ, and Type Ⅲ areas. The northern slope of Malang sag and the eastern margin of Tiaohu sag are defined as the favorable areas for UCG. Figures and Tables | References | Related Articles | Metrics

RESERVOIR ENGINEERING

Development Strategies for Unconventional Oil and Gas Resources in Turpan-Hami Exploration Area XU Jun, YANG Chun, MENG Pengfei 2023, 44 (3):  314-320.  doi: 10.7657/XJPG20230307 Abstract ( 171 )   HTML ( 16 )   PDF (671KB) ( 103 )   Save To accelerate the development and utilization of unconventional oil and gas resources in the Turpan-Hami exploration area, the current development of unconventional resources in China is reviewed. Considering the technical difficulties in development and the mature experience in domestic shale oil and tight gas development, the development strategies for unconventional oil and gas resources in the Turpan-Hami exploration area are discussed. The development strategies for unconventional oil reservoirs are proposed regarding different basins, structural units and target zones. For the Permian shale oil reservoirs in the Malang sag of Santanghu basin, multi-layer development strategy is adopted; along with the construction of the largest carbon reduction base in the eastern Xinjiang, the technology of CO2 full-chain energy replenishment + viscosity-reduction volume fracturing for shale oil is vigorously developed to continuously enhance the recovery of shale oil. For the Permian Mazhong tight oil reservoirs in the Santanghu basin, well group multi-media composite huff-and-puff is adopted to enhance the oil recovery to 15.0%. For the Permian shale oil reservoirs in the Ji 28 block in the Jimsar sag, eastern Junggar basin, based on the successful experience in the Jimsar Shale Oil Demonstration Zone, the shale oil sweet spots are classified and evaluated, their distribution characteristics are clarified, and the drilling rate of Type I + II reservoirs is improved, so as to realize the beneficial development of shale oil. For the Jurassic Sanjianfang tight gas reservoirs in the Shengbei sag of Turpan-Hami basin, pilot tests of geology-engineering integration are performed to increase the length of horizontal section and the drilling rate of reservoir sweet spots, so as to improve the production efficiency of the tight gas reservoirs in the Shengbei sag. Figures and Tables | References | Related Articles | Metrics

Experiment on Collaborative Construction of Reservoir-Type Underground Gas Storage and Natural Gas Flooding: A Case Study of Sanjianfang Formation Reservoir in Pubei Oilfield SI Bao, YAN Qian, LIU Qiang, ZHANG Yanbin, FU Chunmiao, QI Huan 2023, 44 (3):  321-326.  doi: 10.7657/XJPG20230308 Abstract ( 181 )   HTML ( 17 )   PDF (563KB) ( 89 )   Save There are scarce researches on the prediction of collaborative underground gas storage (UGS) capacity and the timing of conversion from the collaborative construction stage to the UGS construction stage. Through core displacement experiments and overburden porosity/permeability experiments, the impacts of long-term water flooding and multiple cycles of gas flooding on UGS capacity were studied. By using the full-diameter core samples from the Sanjianfang formation in Pubei oilfield, an experiment on the whole process of UGS capacity expansion through oil production followed by collaborative UGS operation was carried out for the first time, to identify the influences of multiple cycles of gas flooding on storage capacity, time of capacity establishment, volume proportion of working gas, and recovery rate under two modes (constant-pressure production and regular production). The results show that both long-term water flooding and multiple cycles of gas flooding can improve reservoir properties and can be considered as the factors for increasing UGS capacity. As the number of injection-production cycles increases, the incremental capacity decreases and the working gas volume proportion increases under the two modes. The UGS capacity is basically established after the sixth injection-production cycle under constant-pressure production and after the tenth injection-production round under regular production, with the recovery rate not increasing further. The recovery rate under constant-pressure production is 0.34% higher than that under regular production. Figures and Tables | References | Related Articles | Metrics

CO2 Huff-n-Puff and Storage Test in Extra-High Water Cut Stage in Shanshan Oilfield LI Yanming, LIU Jing, ZHANG Peng, GONG Xuecheng, MA Jianhong 2023, 44 (3):  327-333.  doi: 10.7657/XJPG20230309 Abstract ( 165 )   HTML ( 17 )   PDF (720KB) ( 156 )   Save Based on the pilot test of the CO2 huff-n-puff well group in the Shanshan oilfield, the injection-production performance and the factors influencing CO2 EOR and storage in high water cut stage in low-permeability and low-viscosity oilfields were analyzed. The results show that, in the Shanshan oilfield (medium-deep burial reservoirs), the injected CO2 stays in a supercritical state, and the characteristics of CO2 injection are similar to those of water injection, showing the problems of uneven vertical sweep and planar breakthrough. The CO2 huff-n-puff can be divided into three stages: transient gas flowback, oil enhancement, and gradual invalidation. Three huff-n-puff wells vary greatly in oil replacement rate, indicating that the EOR effect mainly affected by the degree of remaining oil enrichment. The main mechanisms of CO2 storage are dissolution and mineralization, and the simultaneous storage rate can reach as high as 95.6%. Figures and Tables | References | Related Articles | Metrics

Characteristics and Influencing Factors of Natural Gas Gravity Drainage in Sanjianfang Formation Reservoir of Pubei Oilfield XIAO Zhipeng, QI Huan, ZHANG Yizhen, LI Yiqiang, YAO Shuaiqi, LIU Tong 2023, 44 (3):  334-340.  doi: 10.7657/XJPG20230310 Abstract ( 133 )   HTML ( 16 )   PDF (3886KB) ( 115 )   Save To explore the feasibility of natural gas gravity drainage in the Pubei oilfield of the Turpan-Hami basin, the oil displacement characteristics under different operation parameters were clarified. By way of high-pressure physical property analysis, slim tube test, CT scanning imaging, and full-diameter core displacement experiments, the variations of the high-pressure physical properties of the fluids in the Middle Jurassic Sanjianfang formation reservoir before and after the flooding in the Pubei oilfield were analyzed, the minimum miscible pressure of the gas in the Shanshan-Urumqi Gas Pipeline and the West-East Gas Pipeline under current reservoir conditions was calculated, the fluid distribution characteristics and the changes in oil saturation along the core under different displacement methods were compared, and the influences of injection rate, injection pressure, and rock dip angle on natural gas gravity drainage were clarified. The results show that after flooding there are increases in both crude oil density and saturation pressure, an unconspicuous change in viscosity, and significantly decrease contents of C2-C6 contents in the crude oil. The minimum miscibility pressures of the gas in the Shanshan-Urumqi Gas Pipeline and the West-East Gas Pipeline with oil are 48.2 MPa and 49.5 MPa, respectively, both higher than the minimum miscibility pressure of the original oil and gas. Compared with the performance after water flooding, the natural gas gravity drainage reveals very different oil saturations along the core: the oil saturation at the high position of the core is significantly lower than that at the low position, indicating that the natural gas gravity drainage is more effective in displacing the crude oil at the high position. Low injection rate, high displacement pressure, and large dip angle are all beneficial to improving the oil recovery of natural gas gravity drainage. Figures and Tables | References | Related Articles | Metrics

Adaptability Evaluation of Gas Huff-n-Puff in Heavy Oil Reservoirs in Tuha Exploration Area XIA Zhengchun, ZHAO Jian, LIU Feng, QIN Enpeng, CAI Bijin, WANG Qi 2023, 44 (3):  341-346.  doi: 10.7657/XJPG20230311 Abstract ( 141 )   HTML ( 12 )   PDF (539KB) ( 56 )   Save The performance of gas huff-n-puff in heavy oil reservoirs in the Tuha exploration area are declining. Gas huff-n-puff experiments were conducted by using PVT analysis technology to simulate high-temperature and high-pressure environment in the heavy oil reservoirs. CO2, natural gas, and nitrogen were injected respectively into the reservoirs, and then evaluated for adaptability in terms of viscosity reduction, swelling effect, foamy oil range, and residual heavy oil properties. The results show that CO2 huff-n-puff is best performed in viscosity reduction, swelling, and foamy oil range, but the injected CO2 has a significant impact on the residual heavy oil properties by increasing the residual heavy oil viscosity and decreasing the gas dissolution capacity, which is not conducive to multiple rounds of gas huff-n-puff. The natural gas huff-n-puff effect is slightly inferior to that of CO2 huff-n-puff, while the nitrogen huff-n-puff exhibits the worst performance but has a little impact on residual heavy oil properties. Figures and Tables | References | Related Articles | Metrics

Factors Influencing Water Injection Effect in Low Porosity and Low Permeability Heavy Oil Reservoirs WAN Haiqiao, WANG Sheng, LIU Xueliang 2023, 44 (3):  347-351.  doi: 10.7657/XJPG20230312 Abstract ( 142 )   HTML ( 17 )   PDF (539KB) ( 114 )   Save Low porosity and low permeability sandy conglomerate heavy oil reservoirs in the Permian series of the Lukeqin oilfield in Turpan-Hami basin are usually fractured for recovery due to their poor physical properties, strong heterogeneity and low natural productivity. The induced fractures and reservoir heterogeneity lead to poor water injection effect. In order to solve the problems encountered in the development such as prominent areal contradiction, low efficiency, and ineffective areas, water injection is used to replenish the formation energy for increasing single-well production, but the effect in single wells is quite different. The reservoir wettability and water injection process for energy replenishment were studied through physical simulation experiments. The results show that the Permian reservoirs in the Lukeqin oilfield are water-wetting. Fracturing is conducive to the imbibition between fractures and reservoir matrix, which can effectively replenish the formation energy to improve single-well production. The faster the water is injected, the faster the formation energy can be recovered; the higher the well soaking pressure, the higher the oil increment. Combining numerical simulation and in-situ conditions, the injection parameters were optimized. As a result, the effect of water injection was good, with the effective rate reaching 88%. Figures and Tables | References | Related Articles | Metrics

Influences of Superposition of Multi-Block Cumulative Production Index on Estimated Oil Recovery SONG Chengyuan, YANG Xiaoxuan, YUAN Yuying, LI Yanming 2023, 44 (3):  352-358.  doi: 10.7657/XJPG20230313 Abstract ( 143 )   HTML ( 15 )   PDF (596KB) ( 64 )   Save Various blocks of a same reservoir might be developed at different time, which leads to the underestimate of oil recovery when using comprehensive reservoir development data to calibrate oil recovery factor. In order to solve this problem, two blocks with different lag time, productivity and OOIP were designed. Through comparative analysis of indexes, the influencing factors were analyzed quantitatively. The results show that, with the same waterflooding model, the recovery factor estimated by superposing cumulative production index is lower than the sum of the recovery factor estimated separately for each block. The larger the proportion of productivity or geological reserves of a new development block and the later the block is developed, the lower the estimated recovery factor through the superposition of cumulative production index. Therefore, when using waterflooding curves to calibrate recovery factor, the oil reservoir should be divided into several units according to the similar production time as possible to calculate the recovery factor separately; otherwise, calculating recovery factor by superposing cumulative production index will result in a lower calibration of recoverable reserves or recovery factor. Figures and Tables | References | Related Articles | Metrics

APPLICATION OF TECHNOLOGY

Fluid Saturation Correction Method for Sealed Coring Wells in Thin Oil Reservoirs ZHU Yongxian, YAO Shuaiqi, ZHANG Yanbin, HAN Jifan, ZHAO Ruiming 2023, 44 (3):  359-364.  doi: 10.7657/XJPG20230314 Abstract ( 169 )   HTML ( 20 )   PDF (576KB) ( 99 )   Save To determine the fluid saturation under the formation conditions of thin oil reservoirs in the Turpan-Hami basin, based on the data of sealed coring in the Wenmi oilfield and Shanshan oilfield, physical simulation control experiments were performed to simulate the influences of depressurized degassing and evaporation losses on core fluid saturation during coring, and then a fluid saturation correction model suitable for sealed coring of thin oil reservoirs in the Turpan-Hami basin was established. The limit of depressurized degassing loss is clarified, that is, when the initial water saturation is greater than 88% or less than 33%, the depressurized degassing loss is weak and negligible. The new model also takes into account the effects of pore volume change, extraction loss in saturation experiments, and evaporation loss under different flooding conditions on saturation measurement, effectively improving the correction accuracy. The error between the oil saturation derived from the model and that from logging interpretation is 0.17%. Figures and Tables | References | Related Articles | Metrics

Establishment and Application of Functional Mathematical Model for Production Cycle of Oil and Gas Reservoirs MEN Haiwen, ZHANG Jing, WEI Haijun, ZHAO Yang, GAO Wenjun 2023, 44 (3):  365-374.  doi: 10.7657/XJPG20230315 Abstract ( 155 )   HTML ( 19 )   PDF (699KB) ( 103 )   Save The mathematical models for production cycle of oil and gas reservoirs were reviewed systematically. On this basis, the generalized functional production decline formula was introduced to replace the decline function in the generalized whole-process mathematical model for production cycle, and it is no longer necessary to determine the decline function according to the driving type and flow characteristics of the oil and gas reservoirs. Meanwhile, considering that the generalized whole-process mathematical model for production cycle can be integrated, the expressions of its increasing function items were summarized to form three types of increasing function expressions. When the composite time and undetermined parameters take different values, the new generalized whole-process mathematical model for production cycle can not only be converted into the basic mathematical models for various production cycles, but also form other new mathematical models for production cycle, possessing the general formula and extensibility in the whole-process mathematical model for production cycle. In order to reduce the difficulty in solving the undetermined parameters, five simplest and most common methods for solving the composite time formula and functional mathematical model for production cycle are given. The satisfactory application results verify that the new model is worthy of promotion in other oil and gas reservoirs. Figures and Tables | References | Related Articles | Metrics

Facies-Controlled Geostatistical Inversion Method Based on Low-Frequency Model Optimization and Its Application SHI Nan, LIU Yuan, LENG Yue, WEN Yihua, PAN Haifeng, SUN Bo, WANG Bing 2023, 44 (3):  375-382.  doi: 10.7657/XJPG20230316 Abstract ( 194 )   HTML ( 19 )   PDF (9433KB) ( 111 )   Save The oil and gas reservoirs in the Qiketai formation of Middle Jurassic in the Pubei area of Taibei sag, Turpan-Hami basin, are controlled by lithology. Early exploration confirmed that there are thin oil-bearing sand layers with the thickness of 6-15 m at the bottom of the Qiketai formation. It is difficult for conventional inversion methods to predict these sand layers and these methods often yield large errors due to the limitations of the frequency band of seismic data. In order to improve inversion accuracy, a facies-controlled geostatistical inversion method based on low-frequency model optimization was proposed. Combined with the characteristics of large structural relief and greatly varying sedimentary facies in the study area, the low-frequency model was established by combining the compaction trend correction method and the seismic attribute constraint method to obtain the deterministic inversion results. On this basis, a facies-controlled model was established for facies-controlled geostatistical inversion, thus enabling the identification of thin sand layers in the study area. This method effectively complements the low-frequency information missed in seismic signals, and improves the longitudinal resolution of the inversion results. By using this method, a thin sand layer with the thickness of 7 m can be identified, and the inversion result is basically consistent with the actual thickness of sand body, which confirms the effectiveness of this method in predicting thin sand layers in Pubei area. Figures and Tables | References | Related Articles | Metrics