23 April 2022, Volume 49 Issue 2
    

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    PETROLEUM EXPLORATION
  • Exploration discovery and hydrocarbon accumulation characteristics of the Doseo strike-slip and inverted basin, Chad
    DOU Lirong, XIAO Kunye, DU Yebo, WANG Li, ZHANG Xinshun, CHENG Dingsheng, HU Ying
    Petroleum Exploration and Development, 2022, 49(2): 215-223. https://doi.org/10.11698/PED.2022.02.01
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    Several international oil companies had conducted petroleum exploration, but failed to make any commercially viable discoveries in the Doseo Basin for over 30 years. An integrated analysis of hydrocarbon accumulation and enrichment in the basin based on the latest seismic and drilling data combined with exploration practice, tectonic sedimentation and petroleum geological characteristics was completed to find the potential petroleum plays. The Doseo Basin in Chad is a Meso-Cenozoic lacustrine rift basin developed on the Precambrian crystalline basement in the Central African Shear Zone. It is a half graben rift controlled by the strike-slip fault at the northern boundary, and can be divided into two subbasins, an uplift and a slope. The basin experienced two rifting periods in the Cretaceous and was strongly inverted with the erosion thickness of 800-1000 m during the Eocene, and then entered the depression and extinction period. Normal faults and strike-slip faults are developed in the basin, and the boundary faults are inverted faults. The main structural style includes compressed anticlines, fault noses, complex fault-blocks and flower structures. The Lower Cretaceous is the main sedimentary strata, which are divided into the Mangara Group, Kedeni, Doba and Koumra Formations from bottom up. Two transgressive-regressive cycles developed in the Lower Cretaceous with mainly lacustrine, river, deltal, braided river delta, fan delta facies sandstone and mudstone. The effective source rock in the basin is the Lower Cretaceous deep lacustrine mudstone with the type I and type II1 organic matter. Inverted anticlines and fault complicated blocks are the main trap types. The Kedeni Uplift is the most favorable play, followed by the Northern Steep Slope and Southern Gentle Slope. Lateral sealing capacity of faults controls the hydrocarbon abundance.
  • Heterogeneous geological conditions and differential enrichment of medium and high maturity continental shale oil in China
    HU Suyun, BAI Bin, TAO Shizhen, BIAN Congsheng, ZHANG Tianshu, CHEN Yanyan, LIANG Xiaowei, WANG Lan, ZHU Rukai, JIA Jinhua, PAN Zhejun, LI Siyang, LIU Yuxi
    Petroleum Exploration and Development, 2022, 49(2): 224-237. https://doi.org/10.11698/PED.2022.02.02
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    Based on the comparison of basic geological conditions and enrichment characteristics of shale oil plays, the heterogeneity of source and reservoir conditions and differential enrichment of medium-high maturity continental shale oil plays in China have been confirmed. (1) Compared with the homogeneous geological settings and wide distribution of marine shale oil strata in North America, the continental medium and high maturity shale oil plays in China are significantly different in geological conditions generally; continental multi-cyclic tectonic evolution forms multiple types of lake basins in multi-stages, providing sites for large-scale development of continental shale oil, and giving rise to large scale high-quality source rocks, multiple types of reservoirs, and diverse source-reservoir combinations with significant heterogeneity. (2) The differences in sedimentary water environments lead to the heterogeneity in lithology, lithofacies, and organic material types of source rocks; the differences in material source supply and sedimentary facies belt result in reservoirs of different lithologies, including argillaceous and transition rocks, and tight siltstone, and complex source-reservoir combination types. (3) The heterogeneity of the source rock controls the differentiation of hydrocarbon generation and expulsion, the diverse reservoir types make reservoir performance different and the source-reservoir configurations complex, and these two factors ultimately make the shale oil enrichment patterns different. Among them, the hydrocarbon generation and expulsion capacity of high-quality source rocks affects the degree of shale oil enrichment. Freshwater hydrocarbon source rocks with TOC larger than 2.5% and saline hydrocarbon source rocks with TOC of 2% to 10% have high content of retained hydrocarbons and are favorable. (4) High-abundance organic shale is the basis for the enrichment of shale oil inside the source. In addition to being retained in shale, liquid hydrocarbons migrate along laminae, diagenetic fractures, and thin sandy layers, and then accumulate in laminae of muddy siltstone, siltstone, and argillaceous dolomite, and dolomitic siltstone suites etc. with low organic matter abundance in the shale strata, resulting in differences in enrichment pattern.
  • Sinian hydrocarbon accumulation conditions and exploration potential at the northwest margin of the Yangtze region, China
    YANG Yu, WANG Zecheng, WEN Long, XIE Wuren, FU Xiaodong, LI Wenzheng
    Petroleum Exploration and Development, 2022, 49(2): 238-248. https://doi.org/10.11698/PED.2022.02.03
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    Based on outcrop, drilling, logging and seismic data, the reservoir forming conditions, reservoir forming model and exploration potential of the ultra-deep Sinian Dengying Formation at the northwest margin of Yangtze region were examined. (1) This area is in craton rifting stage from Sinian to Early Cambrian, characterized by syn-sedimentary faults and rapid subsidence, significant sedimentary differences, and development of Dengying Formation platform margins on both sides of the rift. (2) The Sinian-Cambrian in this area has two sets of high-quality source rocks, Doushantuo Formation and Maidiping-Qiongzhusi Formation; of which, the latter has a thickness of 150-600 m and hydrocarbon generation intensity of (100-200)×108 m3/km2. (3) The mounds and shoals in the platform margin of Sinian Dengying Formation controlled by faults are thick and distributed in rows and zones; they are reformed by contemporaneous-quasi-contemporaneous and supergene karstification jointly, they become pore-type reservoir with a thickness of 200-400 m. (4) The two sets of source rocks enter oil generation windows from Permian to Early Triassic, and the oil migrates a short distance to the lithologic traps of mounds and shoals to form a huge scale paleo-oil reservoir group; from Late Triassic to Jurassic, the oil in the paleo-oil reservoirs is cracked into gas, laying the foundation of present natural gas reservoirs. (5) The mound-shoal body at the platform margin of Dengying Formation and the two sets of high-quality source rocks combine into several types of favorable source-reservoir combinations, which, with the advantage of near source rock, can form large lithologic gas reservoirs. The Mianyang-Jiange area is a potential large gas field with trillion cubic meters of reserves. According to seismic prediction, the Laoguanmiao structure in this area has the Deng-2 Member mound-shoal reservoir of about 1300 km2, making it a ultra-deep target worthy of exploration in the near future.
  • Key oil accumulation periods of ultra-deep fault-controlled oil reservoir in northern Tarim Basin, NW China
    YANG Shuai, WU Guanghui, ZHU Yongfeng, ZHANG Yintao, ZHAO Xingxing, LU Ziye, ZHANG Baoshou
    Petroleum Exploration and Development, 2022, 49(2): 249-261. https://doi.org/10.11698/PED.2022.02.04
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    A giant fault-controlled oilfield has been found in the ultra-deep (greater than 6000 m) Ordovician carbonate strata in the northern Tarim Basin. It is of great significance for hydrocarbon accumulation study and oil exploitation to determine the key oil accumulation periods. Based on detailed petrographic analysis, fluid inclusion association (FIA) in calcite samples filling in fractures from 12 wells were analyzed, and key accumulation periods of the strike-slip fault-controlled oilfield was studied by combining oil generation periods of the source rocks, formation periods of the fault and traps, and the fluid inclusion data. (1) There are multiple types of FIA, among them, two types of oil inclusions, the type with yellow fluorescence from the depression area and the type with yellow-green fluorescence from the uplift area with different maturities indicate two oil charging stages. (2) The homogenization temperature of the brine inclusions in FIA is mostly affected by temperature rises, and the minimum temperature of brine inclusions symbiotic with oil inclusions is closer to the reservoir temperature during its forming period. (3) FIA with yellow fluorescence all have homogenization temperatures below 50℃, while the FIA with yellow-green fluorescence have homogenization temperatures of 70-90℃ tested, suggesting two oil accumulation stages in Middle-Late Caledonian and Late Hercynian. (4) The Middle-Late Ordovician is the key formation period of the strike-slip fault, fracture-cave reservoir and trap there. (5) The oil generation peak of the main source rock of the Lower Cambrian is in the Late Ordovician, and the oil accumulation stage is mainly the Late Ordovician in the depression area, but is mainly the Early Permian in the uplift area. The key oil accumulation period of the strike-slip fault-controlled reservoirs is the Late Caledonian, the depression area has preserved the primary oil reservoirs formed in the Caledonian, while the uplift area has secondary oil reservoirs adjusted from the depression area during the Late Hercynian. Oil reservoir preservation conditions are the key factor for oil enrichment in the strike-slip fault zone of northern Tarim, and the Aman transition zone in the depression is richer in oil and gas and has greater potential for exploration and development.
  • Evolution of Ordovician YJ1X ultra-deep oil reservoir in the Yuecan oilfield, Tarim Basin, NW China
    YANG Peng, LIU Keyu, LI Zhen, MCINNES Brent Ian Alexander, LIU Jianliang
    Petroleum Exploration and Development, 2022, 49(2): 262-273. https://doi.org/10.11698/PED.2022.02.05
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    Based on a combined in-situ calcite U-Pb dating, molecular geochemical correlations of reservoir oil and extract from reservoir rocks and fluid inclusion analysis, the charge and evolution history of the YJ1X ultra-deep oil reservoir of Ordovician Yijianfang Formation in the southwestern part of the Tabei Uplift has been determined systematically. (1) The reservoir oil, free oil and inclusion oil have similar geochemical characteristics and are presumably derived from marine source rock deposited in similar sedimentary environment. (2) The reservoir oil, free oil and inclusion oil have similar maturities with calculated equivalent vitrinite reflectance values in the range of 0.80%?0.96%. (3) Two types (Ⅰ and Ⅱ) of oil inclusion assemblages (OIAs) have been identified in the reservoir, of which the type Ⅰ represents the original gas-saturated oil entering the trap during the initial oil charge, whereas the type Ⅱ represents undersaturated residual oil retained in the reservoir after minor leakage of light hydrocarbon. (4) The reservoir experienced oil charge only once during the Early Devonian around 425 Ma and has been well preserved after the minor light hydrocarbon leakage in the Middle Devonian. The study shows that there may be old oil and gas accumulations in ultra-deep strata of petroliferous basins with well-developed caprock and stable tectonic background.
  • Segmented evolution of Deyang-Anyue erosion rift trough in Sichuan Basin and its significance for oil and gas exploration, SW China
    MA Kui, WEN Long, ZHANG Benjian, LI Yong, ZHONG Jiayi, WANG Yunlong, PENG Hanlin, ZHANG Xihua, YAN Wei, DING Yi, CHEN Xiao
    Petroleum Exploration and Development, 2022, 49(2): 274-284. https://doi.org/10.11698/PED.2022.02.06
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    Based on analysis of field survey, drilling and seismic data, the formation and evolution process of Deyang-Anyue erosion rift trough in Sichuan Basin was reconstructed, and exploration areas were divided and evaluated. The results show that: (1) Dengying Formation in and around Deyang-Anyue erosion rift trough varies widely in sedimentary characteristics. The Dengying Formation in the northern part of the erosion rift trough developed deep-water sediments, the Dengying Formation in the northern part of the basin varied gradually from basin to slope, platform margin, and limited platform facies, and the Dengying Formation in the middle and southern parts of the trough developed carbonate platform facies. (2) Deyang-Anyue erosion rift trough is formed by extensional rift and karst erosion jointly, the north section of the erosion rift trough is mainly the product of tensile rift, while the middle and south sections are formed by erosion in multi-episodes of Tongwan period. (3) Based on the segmented origins of the erosion rift trough, Dengying Formation in and around it is divided into three exploration fields: lithologic mound and beach bodies at the northern platform margin of the basin, karst mound and beach bodies in the central platform, and karst residual mounds in the central southern trough of the basin, among them, the karst residual mounds in the central southern trough of the basin are a new frontier for natural gas exploration in the basin, and the lithologic mound and beach bodies at the northern platform margin are a new position for increasing the reserves of trillions of cubic meters of natural gas resources in the basin.
  • Restoration of formation processes of dolomite reservoirs based on laser U-Pb dating: A case study of Ordovician Majiagou Formation, Ordos Basin, NW China
    ZHOU Jingao, YU Zhou, WU Dongxu, REN Junfeng, ZHANG Daofeng, WANG Shaoyi, YIN Chen, LIU Yuxin
    Petroleum Exploration and Development, 2022, 49(2): 285-295. https://doi.org/10.11698/PED.2022.02.07
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    To address the issue of non-unique interpretation of dolomite reservoir diagenetic and porosity evolution in the previous qualitative or semi-quantitative studies, we investigate two dolomite reservoir types, i.e. weathering-crust karstic reservoirs and mound-beach reservoirs, in the Ordovician Majiagou Formation, the Ordos Basin using in-situ laser ablation U-Pb dating as well as carbon and oxygen isotopic composition analysis. The results show that: (1) According to the dating of 8 reservoir samples, the Majiagou Formation experienced 5 diagenetic stages (Stage 1: deposition of matrix dolomite or penecontemporaneous dolomitization, in 444.0-494.0 Ma; Stage 2: dogtooth- or blade-shaped dolomite cementation, in 440.0-467.0 Ma; Stage 3: dolomitic silt filling, in 316.5-381.0 Ma; Stage 4: crystalline dolomite filling, in 354.0 Ma; Stage 5: crystalline calcite filling, in 292.7-319.0 Ma). (2) Supra-salt weathering-crust karstic dolomite reservoirs went through several diagenetic processes including penecontemporaneous dolomitization, compaction, weathering-crust karstification, packing, and rupturing in succession. Gypsum mold pores formed in the phase of hypergenic karstification and were filled with such minerals as dolomitic silts and calcites, and thus the porosity decreased from 10%-40% to 3%-8%. (3) Sub-salt mound-beach dolomite reservoirs went through the diagenetic processes including penecontemporaneous dolomitization, compaction, subsea cementation, penecontemporaneous corrosion, infiltration backflow dolomitization, packing, and rupturing. The porosity of reservoirs was originally 10%-30%, decreased to 0-6% due to seawater cementation, rose back to 5%-15% owing to penecontemporaneous corrosion, and finally declined to 2%-6% as a result of crystalline dolomites and calcites packing. The above methodology for the restoration of dolomitization and porosity evolution may be helpful for the restoration of porosity evolution in other basins or series of strata.
  • An unsupervised clustering method for nuclear magnetic resonance transverse relaxation spectrums based on the Gaussian mixture model and its application
    GE Xinmin, XUE Zong’an, ZHOU Jun, HU Falong, LI Jiangtao, ZHANG Hengrong, WANG Shuolong, NIU Shenyuan, ZHAO Ji’er
    Petroleum Exploration and Development, 2022, 49(2): 296-305. https://doi.org/10.11698/PED.2022.02.08
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    To make the quantitative results of nuclear magnetic resonance (NMR) transversal relaxation (T2) spectrums reflect is proposed the type and pore structure of reservoir more directly, an unsupervised clustering method was developed to obtain the quantitative pore structure information from the NMR T2 spectrums based on the Gaussian mixture model (GMM). We conducted the principal component analysis on T2 spectrums in order to reduce the dimension data and the dependence of the original variables. The dimension-reduced data was fitted using the GMM probability density function, and the model parameters and optimal clustering numbers were obtained according to the expectation-maximization algorithm and the change of the Akaike information criterion. Finally, the T2 spectrum features and pore structure types of different clustering groups were analyzed and compared with T2 geometric mean and T2 arithmetic mean. The effectiveness of the algorithm has been verified by numerical simulation and field NMR logging data. The research shows that the clustering results based on GMM method have good correlations with the shape and distribution of the T2 spectrum, pore structure, and petroleum productivity, providing a new means for quantitative identification of pore structure, reservoir grading, and oil and gas productivity evaluation.
  • A three dimensional visualized physical simulation for natural gas charging in the micro-nano pore system
    QIAO Juncheng, ZENG Jianhui, XIA Yuxuan, CAI Jianchao, CHEN Dongxia, JIANG Shu, HAN Guomeng, CAO Zhe, FENG Xiao, FENG Sen
    Petroleum Exploration and Development, 2022, 49(2): 306-318. https://doi.org/10.11698/PED.2022.02.09
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    A micro-nano pore three-dimensional visualized real-time physical simulation of natural gas charging, in-situ pore-scale computation, pore network modelling, and apparent permeability evaluation theory were used to investigate laws of gas and water flow and their distribution, and controlling factors during the gas charging process in low-permeability (tight) sandstone reservoir. By describing features of gas-water flow and distribution and their variations in the micro-nano pore system, it is found that the gas charging in the low permeability (tight) sandstone can be divided into two stages, expansion stage and stable stage. In the expansion stage, the gas flows continuously first into large-sized pores then small-sized pores, and first into centers of the pores then edges of pores; pore-throats greater than 20 μm in radius make up the major pathway for gas charging. With the increase of charging pressure, movable water in the edges of large-sized pores and in the centers of small pores is displaced out successively. Pore-throats of 20-50 μm in radius and pore-throats less than 20 μm in radius dominate the expansion of gas charging channels at different stages of charging in turn, leading to reductions in pore-throat radius, throat length and coordination number of the pathway, which is the main increase stage of gas permeability and gas saturation. Among which, pore-throats 30-50 μm in radius control the increase pattern of gas saturation. In the stable stage, gas charging pathways have expanded to the maximum, so the pathways keep stable in pore-throat radius, throat length, and coordination number, and irreducible water remains in the pore system, the gas phase is in concentrated clusters, while the water phase is in the form of dispersed thin film, and the gas saturation and gas permeability tend stable. Connected pore-throats less than 20 μm in radius control the expansion limit of the charging pathways, the formation of stable gas-water distribution, and the maximum gas saturation. The heterogeneity of connected pore-throats affects the dynamic variations of gas phase charging and gas-water distribution. It can be concluded that the pore-throat configuration and heterogeneity of the micro-nanometer pore system control the dynamic variations of the low-permeability (tight) sandstone gas charging process and gas-water distribution features.
  • Equilibrium modeling of water-gas systems in Jurassic-Cretaceous reservoirs of the Arctic petroleum province, northern West Siberia
    NOVIKOV Dmitry Anatolievich
    Petroleum Exploration and Development, 2022, 49(2): 319-329. https://doi.org/10.11698/PED.2022.02.10
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    To reveal the equilibrium state of oil and gas and water in a petroliferous basin with a high content of saline water, calculations of water-gas equilibrium were carried out, using a new simulation method, for the Arctic territories of the West Siberian oil and gas bearing province. The water-bearing layers in this area vary widely in gas saturation and have gas saturation coefficients (Cs) from 0.2 to 1.0. The gas saturation coefficient increases with depth and total gas saturation of the formation water. All the water layers with gas saturation bigger than 1.8 L/L have the critical gas saturation coefficient value of 1.0, which creates favorable conditions for the accumulation of hydrocarbons; and unsaturated formation water can dissolve gas in the existent pool. The gas saturation coefficient of formation water is related to the type of fluid in the reservoir. Condensate gas fields have gas saturation coefficients from 0.8 to 1.0, while oil reservoirs have lower gas saturation coefficient. Complex gas-water exchange patterns indicate that gas in the Jurassic-Cretaceous reservoirs of the study area is complex in origin.
    • OIL AND GAS FIELD DEVELOPMENT
  • Imbibition characteristics of sandstone cores with different permeabilities in nanofluids
    QIU Rundong, GU Chunyuan, XUE Peiyu, XU Dongxing, GU Ming
    Petroleum Exploration and Development, 2022, 49(2): 330-337. https://doi.org/10.11698/PED.2022.02.11
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    The core imbibition and shifting nuclear magnetic resonance (NMR) imaging experiment has loss of surface oil phase and air adsorption, which will affect the accuracy of the experiment result. To solve this issue, a modified experiment method, in-situ imbibition NMR method has been worked out. This method was used to carry out sandstone core imbibition experiment in nanofluid, and the oil migration images in the entire process were recorded. In combination with physical properties of the sandstone cores and the variations of the driving force during the imbibition process, imbibition characteristics of the sandstone cores with different permeabilities in nanofluid were analyzed. The results show that: the nanofluid can greatly reduce the interfacial tension of oil phase and improve the efficiency of imbibition and oil discharge, the higher the concentration, the lower the interfacial tension and the higher the efficiency of imbibition and oil discharge would be, but when the concentration reaches a certain value, the increase in imbibition and oil discharge efficiency slows down; the rise of temperature can reduce the oil viscosity resistance and interfacial tension, and hence enhance the imbibition and oil discharge rate; when the sandstone core is higher in permeability, the bottom crude oil would migrate upward and discharge during the imbibition, the higher the permeability of the sandstone core, the more obvious this phenomenon would be, and the phenomenon is shown as top oil discharge characteristic; when the sandstone core is low in permeability, the crude oil in the outer layer of the sandstone core would discharge first during the imbibition, then crude oil in the inside of the core would disperse outside and discharge, which is shown as oil discharge characteristic around the core; but under long time effect of nanofluid, the core would become more and more water-wet and reduce in the oil-water interfacial tension, so would have top oil discharge characteristic in the later stage of imbibition.
  • Fully coupled fluid-solid productivity numerical simulation of multistage fractured horizontal well in tight oil reservoirs
    ZHANG Dongxu, ZHANG Liehui, TANG Huiying, ZHAO Yulong
    Petroleum Exploration and Development, 2022, 49(2): 338-347. https://doi.org/10.11698/PED.2022.02.12
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    A mathematical model, fully coupling multiple porous media deformation and fluid flow, was established based on the elastic theory of porous media and fluid-solid coupling mechanism in tight oil reservoirs. The finite element method was used to determine the numerical solution and the accuracy of the model was verified. On this basis, the model was used to simulate productivity of multistage fractured horizontal wells in tight oil reservoirs. The results show that during the production of tight oil wells, the reservoir region close to artificial fractures deteriorated in physical properties significantly, e.g. the aperture and conductivity of artificial fractures dropped by 52.12% and 89.02% respectively. The simulations of 3000-day production of a horizontal well in tight oil reservoir showed that the predicted productivity by the uncoupled model had an error of 38.30% from that by the fully-coupled model. Apparently, ignoring the influence of fluid-solid interaction effect led to serious deviations of the productivity prediction results. The productivity of horizontal well in tight oil reservoir was most sensitive to the start-up pressure gradient, and second most sensitive to the opening of artificial fractures. Enhancing the initial conductivity of artificial fractures was helpful to improve the productivity of tight oil wells. The influence of conductivity, spacing, number and length of artificial fractures should be considered comprehensively in fracturing design. Increasing the number of artificial fractures unilaterally could not achieve the expected increase in production.
  • Mechanisms of water block removal by surfactant micellar solutions in low permeability reservoirs
    LI Junjian, LIU Ben, GUO Cheng, SU Hang, YU Fuwei, MA Mengqi, WANG Lida, JIANG Hanqiao
    Petroleum Exploration and Development, 2022, 49(2): 348-357. https://doi.org/10.11698/PED.2022.02.13
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    The existing researches on surfactant micellar solutions mainly focus on the formulation optimization and core flooding test, and the types and mechanisms of cleanup additives suitable for low permeability reservoir remain unclear. The flowback efficiencies of different types of surfactant micellar solutions were evaluated by core experiments, a multi-level pore-throat system micromodel characterizing pore-throat structures of low permeability reservoir was made, and flooding and flowback experiments of brine and surfactant micellar solutions of different salinities were conducted with the micromodel to show the oil flowback process in micron pores under the effect of surfactant micellar solution visually and reveal the mechanisms of enhancing displacement and flowback efficiency of surfactant micellar solution. During the displacement and flowback of brine and low salinity surfactant micellar solution, many small droplets were produced, when the small droplets passed through pore-throats, huge percolation resistance was created due to Jamin’s effect, leading to the rise of displacement and flowback pressure differences and the drop of flowback efficiency. The surfactant micellar solutions with critical salinity and optimal salinity that were miscible with crude oil to form Winsor Ⅲ micro-emulsion didnot produce mass small droplets, so they could effectively reduce percolation resistance and enhance oil displacement and flowback efficiency.
  • Modeling and simulation of non-isothermal three-phase flow for accurate prediction in underbalanced drilling
    FALAVAND-JOZAEI A, HAJIDAVALLOO E, SHEKARI Y, GHOBADPOURI S
    Petroleum Exploration and Development, 2022, 49(2): 358-365. https://doi.org/10.11698/PED.2022.02.14
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    The present study aims at investigating the effect of temperature variation due to heat transfer between the formation and drilling fluids considering influx from the reservoir in the underbalanced drilling condition. Gas-liquid-solid three-phase flow model considering transient thermal interaction with the formation was applied to simulate wellbore fluid to calculate the wellbore temperature and pressure and analyze the influence of different parameters on fluid pressure and temperature distribution in annulus. The results show that the non-isothermal three-phase flow model with thermal consideration gives more accurate prediction of bottom-hole pressure (BHP) compared to other models considering geothermal temperature. Viscous dissipation, the heat produced by friction between the rotating drilling-string and well wall and drill bit drilling, and influx of oil and gas from reservoir have significant impact on the distribution of fluid temperature in the wellbore, which in turn affects the BHP. Bottom-hole fluid temperature decreases with increasing liquid flow rate, circulation time, and specific heat of liquid and gas but it increases with increasing in gas flow rate. It was found that BHP is strongly depended on the gas and liquid flow rates but it has weak dependence on the circulation time and specific heat of liquid and gas. BHP increase with increasing liquid flow rate and decreases with increasing gas flow rate.
  • Identification and characterization of microfractures in carbonate samples
    PERMADI Pudji, MARHAENDRAJANA Taufan, NANDYA Sesilia, IDEA Kharisma
    Petroleum Exploration and Development, 2022, 49(2): 366-376. https://doi.org/10.11698/PED.2022.02.15
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    Based on the rock typing method of pore geometry and structure (PGS), rock samples from carbonate reservoir A and carbonate reservoir B were classified using data of routine and special core analysis and thin section images, and microfractures in the carbonate reservoir samples were identified and characterized. Establishment of rock types demonstrates that microfractures have developed in all rock types in carbonate reservoir A, but only partially in certain rock types in carbonate reservoir B with porosity of 1%-11%, less vuggy, and hardness of medium hard to hard. The cut-off porosity was determined for each type of rock to distinguish samples with and without conductive microfractures. The impact of conductive microfractures on improving permeability was analyzed. On the basis of relationship of permeability and original water saturation, the permeability equation was derived by certain special core analysis data with conductive microfractures selected by PGS equation, and the permeability of samples with conductive microfractures has been successfully predicted.
    • PETROLEUM ENGINEERING
  • An intelligent identification method of safety risk while drilling in gas drilling
    HU Wanjun, XIA Wenhe, LI Yongjie, JIANG Jun, LI Gao, CHEN Yijian
    Petroleum Exploration and Development, 2022, 49(2): 377-384. https://doi.org/10.11698/PED.2022.02.16
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    In view of the shortcomings of current intelligent drilling technology in drilling condition representation, sample collection, data processing and feature extraction, an intelligent identification method of safety risk while drilling was established. The correlation analysis method was used to determine correlation parameters indicating gas drilling safety risk. By collecting monitoring data in the safety risk period of more than 20 wells, a sample database of a variety of safety risks in gas drilling was established, and the number of samples was expanded by using the method of few-shot learning. According to the forms of gas drilling monitoring data samples, a two-layer convolution neural network architecture was designed, and multiple convolution cores of different sizes and weights were set to realize the vertical and horizontal convolution computations of samples to extract and learn the variation law and correlation characteristics of multiple monitoring parameters. Finally, based on the training results of neural network, samples of different kinds of safety risks were selected to enhance the recognition accuracy. Compared with the traditional BP (error back propagation) full-connected neural network architecture, this method can more deeply and effectively identify safety risk characteristics in gas drilling, and thus identify and predict risks in advance, which is conducive to avoid and quickly solve safety risks while drilling. Field application has proved that this method has an identification accuracy of various safety risks while drilling in the process of gas drilling of about 90% and is practical.
  • Modular zonal fluid sampling and pressure testing technology for production well
    XU Jianguo, YANG Qinghai, YI Peng, HOU Ze, JIA Weite, FU Tao, ZHANG Zonglin, YUE Qingfeng
    Petroleum Exploration and Development, 2022, 49(2): 385-393. https://doi.org/10.11698/PED.2022.02.17
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    To accurately obtain development dynamic data such as zonal pressure and fluid parameters of each oil layer in the late development stage of a high water-cut old oilfield, a modular zonal sampling and testing technology with the characteristics of modularization, full electronic control and rapidity was proposed and developed. Lab testing and on-site testing were carried out. The modular zonal sampling and testing system is composed of 10 functional modules, namely ground control system, downhole power supply, drainage pump, electronically controlled anchor, electronically controlled packer, electronically controlled sampler, magnetic positioning sub, terminal sub, adapter cable, and quick connector etc. Indoor tests have confirmed that the performance parameters of each module meet the design requirements. The downhole function modules of the system can withstand the pressure of up to 35 MPa and temperature of up to 85 ℃. The rubber cylinder of the electronically controlled packer can withstand the pressure difference of above 10 MPa. The electronically controlled anchor has an anchoring force of greater than 6.9 t, and can be forcibly detached in the event of an accident. The discharge pump has a displacement of 0.8 m3/d and a head of 500 m. The electronically controlled sampler can meet the requirement of taking 500 mL of sample in each of the 3 chambers. Field tests in Jilin Oilfield show that the system can realize rapid isolation and self-check of isolation of a production interval downhole, as well as pressure building test layer by layer. The drainage pump can be used to discharge the mixed liquid between the upper and lower packers and near the wellbore to obtain real fluid samples of the tested formation interval. The data obtained give us better understanding on the pay zones in old oilfields, and provide important basis for development plan adjustment, reservoir stimulation, and EOR measures.
  • An analysis of the uniformity of multi-fracture initiation based on downhole video imaging technology: A case study of Mahu tight conglomerate in Junggar Basin, NW China
    ZANG Chuanzhen, JIANG Hanqiao, SHI Shanzhi, LI Jianmin, ZOU Yushi, ZHANG Shicheng, TIAN Gang, YANG Peng
    Petroleum Exploration and Development, 2022, 49(2): 394-402. https://doi.org/10.11698/PED.2022.02.18
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    To solve the problem that the production of Mahu conglomerate reservoir is not up to expectation after the multi-cluster plus temporary plugging fracturing technology is applied in horizontal wells, stages 2-6 in the test well MaHW6285 are selected to carry out erosion tests with different pumping parameters. The downhole video imaging technology is used to monitor the degree of perforations erosion, and then the fracture initiation and proppant distribution of each cluster are analyzed. The results showed that proppant entered 76.7% of the perforations. The proppant was mainly distributed in a few perforation clusters, and the amount of proppant entered in most of the clusters was limited. The proppant distribution in stage 4 was relatively uniform, and the fracture initiation of each cluster in the stage is more uniform. The proppant distribution in stages 2, 3, 5, and 6 was significantly uneven, and the uniform degree of fracture initiation in each cluster is low. More than 70% of the proppant dose in the stage entered clusters near the heel end, so the addition of diverters did not promote the uniform initiation of hydraulic fractures. There was a positive correlation between the amount of proppant added and the degree of perforations erosion, and the degree of perforations erosion ranged from 15% to 352%, with an average value of 74.5%, which was far higher than the statistical results of shale reservoir tests in North America. The use of 180° phase perforation (horizontal direction) can reduce the “Phase Bias” of perforations erosion, promote uniform perforations erosion and fluid inflow. The research results provide the basis for optimizing the pumping procedure, reducing the perforation erosion and improving the success rate of diversion.
  • An optimization method of fidelity parameters of formation fluid sampling cylinder while drilling
    JIANG Chuanlong, YAN Tingjun, ZHANG Yang, SUN Tengfei, CHEN Zhongshuai, SUN Haoyu
    Petroleum Exploration and Development, 2022, 49(2): 403-410. https://doi.org/10.11698/PED.2022.02.19
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    A design idea of fidelity sampling cylinder while drilling based on surface nitrogen precharging and supplemented by downhole pressurization was proposed, and the working mode and optimization method of sampling parameters were explored. The nitrogen chamber in the sampling cylinder functions as an energy storage air cushion, which can supplement the pressure loss caused by temperature change in the sampling process to some extent. The downhole pressurization is to press the sample into the sample chamber as soon as possible, and further increase the pressure on sample to make up for the pressure that the nitrogen chamber cannot provide. Through analysis of the working mode of the sampling fidelity cylinder, the non-ideal gas state equation was used to deduce and calculate the optimal values of fidelity parameters such as pre-charged nitrogen pressure, downhole pressurization amount and sampling volume according to whether the bubble point pressure of the sampling fluid was known and on-site emergency sampling situation. Besides, the influences of ground temperature on fidelity parameters were analyzed, and corresponding correction methods were put forward. The research shows that the fidelity sampling cylinder while drilling can effectively improve the fidelity of the sample. When the formation fluid sample reaches the surface, it can basically ensure that the sample does not change in physical phase state and keeps the same chemical components in the underground formation.
    • COMPREHENSIVE RESEARCH
  • Earth energy evolution, human development and carbon neutral strategy
    ZOU Caineng, MA Feng, PAN Songqi, LIN Minjie, ZHANG Guosheng, XIONG Bo, WANG Ying, LIANG Yingbo, YANG Zhi
    Petroleum Exploration and Development, 2022, 49(2): 411-428. https://doi.org/10.11698/PED.2022.02.20
    Abstract ( ) Download PDF ( ) Rich HTML   Knowledge map Save
    Energy is the basis of human development and the impetus of society progress. There are three sources of energy: energy of celestial body outside the Earth, the Earth energy and energy of interaction between the Earth and other celestial bodies. Meanwhile, there are three scales of co-evolution: the evolution of the Sun-Earth-Moon system on an ultra-long time scale has provided energy sources and extra-terrestrial environmental conditions for the formation of the Earth system; the evolution of the Earth system on a long time scale has provided the material preconditions such as energy resources and suitable sphere environment for life birth and the human development; on a short time scale, the development of human civilization makes the human circle break through the Earth system, expanding the extraterrestrial civilization. With the co-evolution, there are three processes in the carbon cycle: inorganic carbon cycle, short-term organic carbon cycle and long-term organic carbon cycle, which records human immoderate utilization of fossil energy and global sphere reforming activities, breaking the natural balance and closed-loop path of the carbon cycle of the Earth, causing the increase of greenhouse gases and global climate change, affecting human happiness and development. The energy transition is inevitable, and carbon neutrality must be realized. Building the green energy community is a fundamental measure to create the new energy system under carbon neutrality target. China is speeding up its energy revolution and developing a powerful energy nation. It is necessary to secure the cornerstone of the supply of fossil energy and forge a strong growing pole for green and sustainable development of new energy. China energy production and consumption structure will make a revolutionary transformation from the type of fossil energy domination to the type of new energy domination, depending on a high-level self-reliance of science and technology and a high-quality green energy system of cleaning, low-carbon, safety, efficiency and independence. Energy development has three major trends: low-carbon fossil energy, large-scale new energy and intelligent energy system, relying on the green innovation, contributing the green energy and constructing the green homeland.
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