23 July 2016, Volume 43 Issue 5
    

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  • Relationships between wetness and maturity of coal-derived gas in China
    Dai Jinxing, Ni Yunyan, Zhang Wenzheng1, Huang Shipeng, Gong Deyu, Liu Dan
    Petroleum Exploration and Development. 2016, 43(5): 675-677.
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Owing to its limited homologous, simple structure, small molecular weight and radius, natural gas could diffuse easily and migrate in a long distance, which greatly increases the difficulties of the study of source rock maturity. So in this paper we study the relationship between natural gas wetness and source rock maturity. Based on 49 coal-derived gas samples from the Ordos, Sichuan, Bohai Bay, Qiongdongnan, Junggar and Turpan–Hami basins in China with integral molecular series, it is discovered that the wetness of natural gas decreases with the maturity (Ro) of source rock. The negative correlation between wetness and maturity was established. Since the wetness could be easily acquired, the Ro could be quickly calculated based on the relationship, which provides important basis for gas source definition and resource evaluation.
  • Classification and hydrocarbon distribution of passive continental margin basins
    Wen Zhixin, Xu Hong, Wang Zhaoming, He Zhengjun, Song Chengpeng, Chen Xi, Wang Yonghua
    Petroleum Exploration and Development. 2016, 43(5): 678-688.
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    Sixty-six passive continental margin basins around the world were compared comprehensively from the aspect of seismogeology on the basis of plate tectonics. According to their structural differences, passive continental margin basins were classified into seven subdivisions, i.e., rifted basin, non-saline faulted depression basin, saline faulted depression basin, non-saline depression basin, saline depression basin, delta reformed basin and positive reverse deformed basin. The passive continental margin basins around the world have been generated with the formation of Mesozoic and Cenozoic Atlantic and Indian Oceans and they have experienced superimposition of three prototypes, including intra-continental rift in rifting period, intercontinental rift in transitional period and passive continental margin in drifting period. In rifted basins, the petroleum systems are mainly located in the lower lacustrine/marine rift series of strata and the thinner depression series of strata at the upper part are only regional cap-rocks. Large oil and gas fields are mainly concentrated in structural traps of rift series of strata. In non-saline faulted depression basins, hydrocarbon generation and expulsion peaks occur in both upper thicker marine depression series of strata and lower rift series of strata. Reservoirs are formed in the structures of rift series of strata, and oil and gas are highly concentrated at slope fans in depression series of strata. In saline faulted depression basins, large oil and gas fields are mainly distributed in the lagoon carbonate rocks of subsalt series of strata and the deepwater slope fans of suprasalt depression series of strata. In saline depression basins, only petroleum systems in depression series of strata are active, and various traps are developed, such as slope fan, salt structure and bioherm. In non-saline depression basins, large oil and gas fields are mainly located in submarine fan groups of depression series of strata because this type of basins are of narrow continental shelf and steep continental slope. In delta reformed basins, four major ring-like structure belts (i.e., growth faulting-mud diapir-thrust nappe-foredeep gentle slope) are formed from the shore to the deepwater and large oil and gas fields can be formed in each belt. Positive reverse reformed basins are the passive continental margin basins which are influenced by global orogenesis since the Miocene. In this type of basins, oil and gas are concentrated in compressional anticlines of reverse series of strata.
  • Restoration of paleokarst landform and its geological significance: A case from Middle Permian Maokou Formation in northwestern Sichuan Basin
    Tang Dahai12; Xiao Di13; Tan Xiucheng3; Li Haiyun3; Xie Jirong4; Liu Hong1; Yang Xun4; Zhang Benjian15
    Petroleum Exploration and Development. 2016, 43(5): 689-695.
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Based on the analysis of deposition and tectonism, “residual thickness method” is used to restore the paleokarst landform of Middle Permian Maokou Formation in northwestern Sichuan Basin. With the feature of plain with karst hilllock, the paleokarst landform in this area can be classified into three secondary geomorphic units, karst platform, karst slope and karst groove, in which the karst hillocks and monadnocks on karst platform and karst slope are the favorable zones for the development of karst reservoirs, and favorable exploration zones in the next step. Furthermore, in the karst grooves, the Maokou Formation are often denuded into Members Mao 3 or Mao 2, and the seismic profiles show the top of Maokou Formation in karst groove is missing due to denudation. Members Mao 4 and Mao 3 are generally preserved in the karst platform. The seismic profiles across the karst platform and karst groove show that the NE and NW striking erosion grooves were the result of differential uplift and erosion caused by basement faulting at the end of Middle Permian, which then successively developed and formed the NW striking Guangyuan-Wangcang and the NE striking Jiangyou-Guangyuan oceanic troughs in Changxing Period. It is suggested to pay more attention to the geologic research and exploration of the shallow carbonate platform areas adjacent to the syneclise and trough in fairly deep water.
  • Genetic connection between mud shale lithofacies and shale oil enrichment in Jiyang Depression, Bohai Bay Basin
    Wang Yong1, Wang Xuejun; Song Guoqi; 2Liu Huimin; Zhu Deshun; Zhu Deyan; Ding Juhong; Yang Wanqin; Yin Yan; Zhang Shun; Wang Min
    Petroleum Exploration and Development. 2016, 43(5): 696-704.
    Abstract ( ) Download PDF ( ) Knowledge map Save
    By using microscope, argon ion polishing technology, nuclear magnetic resonance (NMR), scanning electron microscopy, and hydrocarbon generation and expulsion simulation, reservoir properties, oiliness and shale oil mobility of different mud shale lithofacies were examined with the mud shale in Jiyang Depression, Bohai Bay Basin as the example. The relationship between lithofacies type and shale oil enrichment was analyzed. Based on the rock composition, sedimentary structures and abundance of organic matter, a mud shale lithofacies classification standard for the upper submember of the 4th Member to the lower submember of the 3rd Member of Paleogene Shahejie Formation (Es4s-Es3x) was established. Six lithofacies are developed in the target formation, in which the laminar organic-rich lithofacies formed in the alternating mechanical transportation deposition and chemical deposition, not only has the highest TOC, S1, oil saturation, movable oil saturation, content of low-carbon light components and oil generation and expulsion rate, but also has various types of reservoir space, abundant pores, and organic network system and interlayer micro-fracture system which can serve as high-speed channels for shale oil and gas migration, so this lithofacies is favorable for shale oil enrichment.
  • Carbon isotopic composition of shale gas in the Silurian Longmaxi Formation of the Changning area, Sichuan Basin
    Feng Ziqi; Liu Dan; Huang Shipeng; Wu Wei1; Dong Dazhong; Peng Weilong ; Han Wenxue
    Petroleum Exploration and Development. 2016, 43(5): 705-713.
    Abstract ( ) Download PDF ( ) Knowledge map Save
    A comprehensive analysis was carried out on the geochemical characteristics of 15 shale gas samples from the Changning area to study the carbon isotopic composition features of shale gas and the reversal cause of carbon isotopic composition in post-mature shale gas in the Silurian Longmaxi Formation of the Changning area, Sichuan Basin. Through the analysis of alkane gas component and carbon isotopic composition, combining with the research on carbon isotopic composition from the Longmaxi Formation of the Fuling and Weiyuan areas in Sichuan Basin, the methane from the Longmaxi Formation shale gas accounts for 97.11% to 99.45%, the average gas wetness is 0.49% representing typical dry gas, abnormal average δ13C1 value as ?28.2‰ and the average of δ13C2 values is ?33.2‰, in view of sapropel-type kerogen, the Longmaxi Formation shale gas belongs to the typical oil-associated gas. With the increasing degree of thermal evolution, the wetness of shale gas decreases gradually, and carbon isotopic composition of methane becomes heavier, and the carbon isotopic composition of ethane and propane will reverse, but the carbon isotopic composition of ethane and propane in the post-mature shale gas of the Changning area stays in the post-stage of reverse and will not get continuously heavier. The abnormal heavy carbon isotopic composition of methane and the reversal phenomenon of carbon isotopic (δ13C1>δ13C2>δ13C3) mainly generate from the secondary cracking effect in the post-mature stage and reactions between ethane with ferrous metals and water under Reileigh fractionation situation. Furthermore, the high temperature is also one of the important influence factors.
  • Formation and distribution of tuffaceous tight reservoirs in the Permian Tiaohu Formation in the Malang sag, Santanghu Basin, NW China
    Ma Jian; Huang Zhilong; Zhong Dakang; Liang Shijun1; Liang Hao1; Xue Dongqing; Chen Xuan1; Fan Tanguang1
    Petroleum Exploration and Development. 2016, 43(5): 714-722.
    Abstract ( ) Download PDF ( ) Knowledge map Save
    ased on analysis of major and trace elements, observation of thin sections, cathodoluminescence and scanning electron microscope of tuff samples, in combination with the restoration of paleotopography in the Malang sag, the formation and distribution characteristics of the Permian Tiaohu Formation tuff tight reservoirs in the Santanghu Basin are examined. The analysis shows that the tuff samples of the Tiaohu Formation are acid-intermediate, and they are the product of the end of the volcanic eruption cycle. The tuff reservoir rock includes vitric tuff, crystal-vitric tuff, and pelitic tuff, among which, vitric tuff has the best physical properties, followed by crystal-vitric tuff, and pelitic tuff is the poorest. Vitric tuff is usually distributed further away from the crater zone laterally and vertically in the central-lower part of the tuff. Crystal-vitric tuff, mostly interbedded with vitric tuff, is usually distributed near the crater zone laterally and also vertically in the central-lower part of the tuff. Pelitic tuff is generally distributed far away from the volcanic crater on the plane, and in the upper part of the tuff vertically. Types of tuffs are affected by the distance from the volcanic activity belt, and the thickness of tuff is controlled by both volcanic activity belt and sedimentary paleotopography. Thus, depositional depressions on both sides of volcanic activity belt are the favorable locations for the development of tuff. It is predicted that there are five thickness centers of tuff in the Tiaohu Formation of Malang sag (Wellarea M1, L1, M56, M7 and southwest of M7), of which the biggest thickness of tuff is up to approximately 40 m.
  • Accumulation process and pattern of oolitic shoal gas pools in the platform: A case from Member 3 of Lower Triassic Feixianguan Formation in the Heba area, northeastern Sichuan Basin
    Li Hongtao
    Petroleum Exploration and Development. 2016, 43(5): 723-732.
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Combined with the regional sedimentary burial history and trap tectonic evolution history, the gas source, pool-forming periods and accumulation process of the oolitic shoal limestone gas pool in the Lower Triassic Feixianguan Formation Member 3 were researched in the Heba area of northeast Sichuan Basin. The gas source was mainly derived from the underlying Upper Permian Wujiaping Formation (or Longtan Formation) according to the analysis results of carbon isotopic compositions of individual hydrocarbons. The analysis of homogenization temperature for fluid inclusions shows, the gas pool has experienced multi-stage gas generation and migration, which occurred in the Late Jurassic to Early Cretaceous, matched with the generating peak of the Upper Permian source rocks, and represented the main period for hydrocarbon accumulation. The formation process of the Heba area had structural prototype in Indo-Chinese Epoch, and was relatively stable stage in the Jurassic to Early Cretaceous, and was formed like present structure in the Late Cretaceous, and was complicated in the Cenozoic Himalayan period. It is predicted that the sedimentary micro-paleogeomorphology highs, faults or fracture relative development area and the ancient-modern structure development zone are favorable for oolitic shoal limestone gas pools in Northeast Sichuan.
  • Calculation model for on-way parameters of horizontal wellbore in the superheated steam injection
    Fan Zifei; He Congge; Xu Anzhu
    Petroleum Exploration and Development. 2016, 43(5): 733-739.
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Due to superheated steam as a pure gas, the ordinary steam model for the calculation of horizontal well-bore parameters based on two phases flow theory isn’t applicable to the superheated steam injection process. According to the conservation of mass, conservation of momentum and conservation of energy, a calculation model for on-way parameters of horizontal well-bore in the superheated steam injection considering the steam phase changing is set up. The on-way parameters of temperature, pressure and dryness of a horizontal well injected superheated steam from Kazakhstan Kumsai oilfield is calculated using the model, and the calculation result of the new model is in good agreement with that of the field data, which verifies the effectiveness of the model. Sensitivity analysis indicates that the length to the heel of horizontal well undergoing the steam phase state changing increases as the injection rate or the degree of superheat increases, but the increase extent is not significant when the injection rate is larger than 8 t/h or the degree of superheat is larger than 80 ℃. In the permeability distribution pattern that the permeability increases along the horizontal well-bore, steam temperature is decreased at the lowest rate and the length to the heel of horizontal well undergoing the steam phase changing is the longest.
  • Natural fracture distribution and a new method predicting effective fractures in tight oil reservoirs of Ordos Basin, NW China
    Fan Jianming; Qu Xuefeng; Wang Chong; Lei Qihong; Cheng Liangbing; Yang Ziqing
    Petroleum Exploration and Development. 2016, 43(5): 740-748.
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Based on core, imaging logging, and thin section data, the distribution features of natural fractures in the tight oil reservoirs of the Ordos Basin are examined. The tight reservoirs in the Ordos Basin are rich in natural fractures, the fractures are mainly high-angle structural shear fractures in continuous step arrangement. Affected by rock mechanical anisotropy and present stress field, the NE trending fractures are the dominating seepage flow direction. These fractures feature high angle, small cutting depth, small aperture and short extension, controlled by rock lithology and single layer thickness in development degree, natural fractures are most developed in fine siltstone, most undeveloped in mudstone. The thinner the single layer, the more developed the natural fractures will be. Based on distribution features of natural fractures and quantitative evaluation of natural fracture characteristic parameters, by using reservoir matrix and natural fracture geologic modeling, a comprehensive reservoir geologic model considering natural fractures was built, by using reservoir numerical simulation modeling inversion, the plane distribution of effective natural fractures was found out, and the contribution of natural fractures to single well production was quantitatively evaluated at around 30.0%?50.0%. The research results are of great significance for well-pattern deployment and optimization of development technical policies of similar reservoirs.
  • Formation water evaporation induced salt precipitation and its effect on gas production in high temperature natural gas reservoirs
    Cui Guodong; Ren Shaoran; Zhang Liang; Ren Bo1; Zhuang Yuan; Li Xin; Han Bo; Zhang Panfeng
    Petroleum Exploration and Development. 2016, 43(5): 749-757.
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    To study the pattern of formation water evaporation and salt precipitation, based on the oil-gas-water three phase thermodynamic equilibrium, the principle of salt dissolution/precipitation, and results of formation water evaporation and salt precipitation experiment, a comprehensive salt precipitation model considering formation water evaporation, precipitation of NaCl in water, and reservoir porosity and permeability variations was established to analyze the salt precipitation and its influence factors during the development of high temperature gas reservoir, and some methods preventing and removing salt precipitation were proposed. The study results show that salt precipitation usually occurs in production well area during development of gas reservoir. When the initial formation water saturation is less than the irreducible water saturation, the concentration of precipitated salt from production well area will be lower, and the influence of salt precipitation on reservoir can be ignored. When initial formation water saturation is higher than irreducible water saturation, the flowing formation water constantly carries NaCl to the well bore, leading to massive precipitation of NaCl in the production well area, damaging or even plugging the reservoir completely, and shortening the development life cycle of gas reservoir at last. The increase of reservoir temperature, formation water salinity and reservoir porosity will intensify reservoir damage caused by salt precipitation. But the increase of production rate and reservoir permeability will reduce reservoir damage caused by salt precipitation. The results of this study can guide the prevention and removal of salt precipitation, enhancement of gas reservoir productive capacity and secondary development of high temperature gas reservoir.
  • Computation method for water influx in different layers of natural edge water
    Zhang Jiqun; Deng Baorong1; Hu Changjun; Chang Junhua1; Li Xinhao1; Li Hua1; He Dongmei2
    Petroleum Exploration and Development. 2016, 43(5): 758-763.
    Abstract ( ) Download PDF ( ) Knowledge map Save
    To scientifically and objectively evaluate the development effectiveness and separated layer production of favorable natural water edge reservoir and to improve the computation method for volumes of water influx in different layers, this study applies a novel technique to simulate the process of natural water invasion by utilizing various geological and single wells’ data and deploying virtual injection wells at the oil-water interface of arbitrary shape. The denser the virtual injection wells are deployed, the more precise the water invasion process can be. This study calculates water influx direction and intrusion resistance of natural edge water by discriminating connection relationship of separated layer between the virtual injection wells and production wells. Referring to hydropower similarity principle, it calculates intrusion resistance of each layer and total invasion resistance of the reservoir, thus deriving the volume of water influx of each layer. The new method has been implemented in software and applied to over ten blocks in Dagang Oilfield, Liaohe Oilfield, Jidong Oilfield, etc. The results have shown that the method is more accurate for split production data to calculate separated layer water influx volume in each unit in natural water edge reservoir.
  • Application of wettability alteration in the exploitation of unconventional liquid resources
    Alvarez J O; Schechter D S
    Petroleum Exploration and Development. 2016, 43(5): 764-771.
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    This study investigates the wettability measurement methods suitable for unconventional reservoirs, summarizes the wettability characteristics of unconventional reservoir rocks, overviews the current state-of-the-art applications of wettability alteration in unconventional liquid resources, and recommends experimental procedures for evaluating effects of surfactants on wettability in unconventional liquid resources. Contact angle determination, NMR (Nuclear Magnetic Resonance) method and Zeta potential measurement are the most appropriate means to estimate wettability in unconventional reservoirs. Unconventional reservoirs exhibit mixed wettability from intermediate-wet to oil-wet. To this date, surfactants are the only ones experimentally reported on applications of wettability alteration in unconventional liquid resources. Altering wettability in unconventional liquid resources as an improved oil recovery method can be reached by adding surfactants to fracturing fluids. Stability test, wettability alteration experiment, interfacial tension experiment, spontaneous imbibition experiment, forced imbibition experiment and adsorption experiment can be used when evaluating the efficiency of surfactants in altering wettability and recovering hydrocarbons from unconventional reservoirs.
  • Stress interference calculation model and its application in volume stimulation of horizontal wells
    Xu Yun; Chen Ming; Wu Qi; Li Deqi1; Yang Nengyu2; Weng Dingwei; Guan Baoshan
    Petroleum Exploration and Development. 2016, 43(5): 772-779.
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    A new model for calculating stress fields of fractured media was established by incorporating stress correction factor based on displacement discontinuity boundary element method. The accuracy of the new model is close to 3D displacement discontinuity model, and its calculation is significantly simplified. An algorithm for multi-fracture propagation geometry was proposed based on fracture criterion and fracture growth rate law, which was used to investigate multi-fracture stress interference and propagation geometry. The results show that the size of stress interference is determined by the shortest dimension of fracture face, which is 1.2?1.5 times fracture height when fracture length is longer than fracture height, and 1.2?1.5 times fracture length when fracture length is shorter than fracture height. The larger the ratio of fracture spacing to fracture height, or the smaller the ratio of net pressure to the differential principle stress, the more close to well-bores the deviation position is, and the larger the deviation angle is. The middle fracture propagates to the fracture at a further distance and one dominating fracture propagates longest when three-cluster fractures are not equally spaced, while the middle fracture propagates straightly when three-cluster fractures are equally spaced.
  • Molecular simulation of CO2/CH4 competitive adsorption in organic matter pores in shale under certain geological conditions
    Wang Xiaoqi; Zhai Zengqiang1; Jin Xu; Wu Songtao; Li Jianming; Song Liang; Liu Xiaodan
    Petroleum Exploration and Development. 2016, 43(5): 780-786.
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    To reveal competitive absorption behavior between CH4 and CO2 in organic matter (OM) nanopores, OM pore structure was first characterized using focused ion beam?scanning electron microscope (FIB-SEM) and pore-size distribution was studied using N2 adsorption, using Lower Silurian Longmaxi shale in Sichuan Basin as sample. Then a simplified pillar-layer model was used to study CH4 adsorption behavior and competitive adsorption effect between CO2 and CH4, using grand canonical Mote Carlo (GCMC) method. Research indicates that nanopores with good connectivity widely exist in OM, offering important storage space for absorbed shale gas. The amount of absorbed CH4 can increase with lower temperature and increased pressure, and overpressure will significantly increase the amount of CH4 absorbed underground; CO2 shows high competitive absorption ability; CO2/CH4 selectivity coefficient decreases dramatically with increasing temperature or pressure, or both, and it corresponds to deeper burial depth. CO2 EGR during shale gas exploration will be more efficient if it is conducted after the pressure drops to a certain degree.
  • Pressure controlling method for managed pressure drilling with supercritical carbon dioxide as the circulation fluid
    Song Weiqiang; Ni Hongjian1; Wang Ruihe; Shen Zhonghou; Zhao Mengyun2
    Petroleum Exploration and Development. 2016, 43(5): 787-792.
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    Heat transfer along the wellbore was analyzed, and then a closed mathematical model, which fully couples the hydrostatic pressure, temperature, physical properties of CO2 and friction, was established to keep bottom-hole pressure constant during drilling process. Based on the pressure profile in wellbore achieved for a certain surface back pressure, a pressure controlling method for managed pressure drilling with supercritical carbon dioxide was presented. The influences of mass flow rate, well depth and inlet temperature on the annulus pressure profile and surface back pressure were investigated. The results show that, the pressure profile is almost in linear correlation with well depth in the annulus, which provides convenience for well control. The needed back pressure (applied by surface choke) decreases with increasing mass flow rate and decreasing well depth. The impact of inlet temperature on the annulus pressure profile, surface back pressure and flow friction is negligible. It also shows that the density of CO2 increases significantly and abruptly at a critical pressure. It is suggested that the storage pressure of CO2 in surface tank be larger than the critical pressure for a certain temperature.
  • Viscosity prediction model optimization for Saraline-based super lightweight completion fluid at high pressure and temperature
    Amir Zulhelmi; Jan Badrul Mohamed; Wahab Ahmad Khairi Abdul; Khalil Munawar1; Ali Brahim Si; Chong Wen Tong
    Petroleum Exploration and Development. 2016, 43(5): 793-798.
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    nvestigation and analysis of the viscosity variation of Saraline-based super lightweight completion fluid (SLWCF) at high pressure and temperature were reported, and the viscosity prediction model was optimized. Viscosity measurements were carried out at temperature and pressure ranging from 298.15 K to 373.15 K, and 0.10 MPa to 4.48 MPa respectively. The data analysis reveals that the reduction of viscosity as a function of temperature may be divided into two regions, i.e. significant viscosity reduction at low temperature and fairly slow viscosity reduction at high temperature; the viscosity of Saraline-based SLWCF is less affected by the changes of pressure. The experimental data were fitted to four different viscosity-temperature-pressure models. The results show that, the modified Mehrotra and Svrcek’s and Ghaderi’s models are able to satisfactorily predict the viscosity value and measured value and describe the viscosity property at high pressure and temperature. The comparison with the Sarapar-based SLWCF reveals that the viscosity of Sarapar-based SLWCF is more affected by temperature than the Saraline-based SLWCF; pressure seems to have negligible effect on Saraline-based SLWCF viscosity; the modified Mehrotra and Svrcek’s and Ghaderi’s models are able to give more reliable viscosity predictions for Saraline-based SLWCF than for Sarapar-based SLWCF.
  • Impact of wellbore fluid properties on trapped annular pressure in deepwater wells
    Zhang Bo; Guan Zhichuan; Sheng Yanan; Wang Qing; Xu Chuanbin
    Petroleum Exploration and Development. 2016, 43(5): 799-805.
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    To reduce the threat of trapped annular pressure on deepwater wells safe production, this study established a model of calculating trapped annular pressure, examined the influence of wellbore fluid properties on trapped annular pressure, and analyzed the sensitivities and engineering feasibilities of controllable factors. To realize the calculation of trapped annular pressure under multiple annuli with liquid, a volume balance matrix was built according to compatibility principle and a wellbore temperature computing model was built based on wellbore-formation coupled heat transfer. Annular pressure decreases as the expansion-compression ratio of annular fluid reduces. Decreasing annular saturation can eliminate annular pressure radically and then a formula was proposed to give extreme annular saturation. The increase of production fluid specific heat capacity and flow rate leads to enhancement of annular pressure. Annular pressure keeps a linear relation to production fluid hole bottom temperature and the wellhead temperature can reflect the value of annular pressure. The water ratio increase of production fluid causes dynamic increase of annular pressure. The sensitivity of annular saturation is much higher than other factors. Decreasing annular liquid thermal conductivity has relatively higher engineering feasibility. The annular pressure can be controlled effectively by developing subsea wellheads with the ability to release annular fluid, highly compressible materials and downhole thermal-insulated fluids.
  • Improvement of Levenberg-Marquardt algorithm during history fitting for reservoir simulation
    Zhang Xian; Awotunde A A1
    Petroleum Exploration and Development. 2016, 43(5): 806-815.
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    In order to estimate reservoir parameters more effectively by history fitting, DE (Differential Evolution) was proposed to estimate the optimum damping factor so that the standard Levenberg-Marquardt algorithm was improved, and the improved algorithm was validated by analysis of examples. The standard LM algorithm uses trial-and-error method to estimate the damping factor and is less reliable for large scale inverse problems. DE can solve this problem and eliminate the use of line search for an appropriate step length. The improved Levenberg-Marquardt algorithm was applied to match the histories of two synthetic reservoir models with different scales, and compared with other algorithms. The results show that: DE speeds up the convergence rate of the LM algorithm and reduces the residual errors, making the algorithm suitable for not only small and medium scale inverse problems, but also large scale inverse problems; if the iteration termination criteria of LM algorithm is preset, the improved algorithm will save the number of iterations and reduce the total time greatly needed for the LM algorithm, leading to higher efficiency of history matching.
  • Directional attraction of fluid surface wave caused by vertically oscillating prisms
    Yang Hong1, 2; Peng Shiliu3; Mao Dongfeng2; Ma Yuquan4; Zeng Shuangxiong4; Song Yunxuan4
    Petroleum Exploration and Development. 2016, 43(5): 816-819.
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    Experiments show that the surface wave, which is caused by a triangular prism performing simple harmonic vibration with low frequency and small amplitude on fluid surface, has directional force on float. A series of experiments and an in-depth study about this phenomenon were carried out, and the characteristics of fluid surface wave from different structures oscillation were analyzed. Experiments were launched with different vertical oscillating structures, such as triangular prism, quadrangular prism, hexagonal prism and the cylinder. The results show that the surface wave, on the direction directly opposite to the prism edge, can attract the floats, while the wave on the direction directly opposite to the prism facet has repelling interection. The relationship between the strength of attraction and sharpness of the angle is non-linear. The sharper the angle, the stronger the attraction force. When the prism becomes a cylinder which means without angle, the attraction will disappear. The experiment found and verified the fluid surface wave caused by specific structure oscillating prisms has directional attraction interection. The results are helpful for cleaning up pollutants and collecting spill oil on the water.
  • Development of sedimentary geology of petroliferous basins in China
    Zhu Xiaomin1; Zhong Dakang1; Yuan Xuanjun2; Zhang Huiliang3; Zhu Shifa1; Sun Haitao1; Gao Zhiyong2; Xian Benzhong1
    Petroleum Exploration and Development. 2016, 43(5): 820-829.
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    This paper gives a contrastive analysis of the main progress made in petroliferous basins sedimentary geology domestically and internationally, and discusses the main problems and their solutions in the development of petroliferous basins sedimentology in China, including coarse-grained depositional sysytem, shallow-water deltic depositional system, beach bar depositional system, deep-water gravity flows, fine-grained depositional sysytem, carbonate reefs, mixosedimentite, microbialite, seismic sedimentology and sedimentary physical simulation. It also reveals the developing gap of Chinese sedimentology in the areas of microbialite and sedimentary simulation, etc. and analyzes the recovery of sedimentary features and paleogeography pattern of prototype basins, multi-scale paleogeographic recovery during major tectonic movements, the different explanation of new sedimentology theories in the deep-buried new sandbodies and old sandbodies development regularities. The paper details the difficulties when it comes to the typical depositional systems combination and the setup of sedimentary models in China. Therefore, the developing tendency is described of sedimentology theories like source to sink, sedimentary dynamics as well as regional sedimentology in China, seismic sedimentology, and studying methods and technologies in sedimentary simulation.
  • Source of condensate oil in the middle of southern margin, Junggar Basin, NW China
    Chen Jianping1, 2, 3; Deng Chunping1, 2, 3; Wang Xulong4; Ni Yunyan1, 2, 3; Sun Yongge5; Zhao Zhe1; Wang Peirong3; Liao Jiande6; Zhang Dijia1, 2, 3; Liang Digang1, 2, 3
    Petroleum Exploration and Development. 2016, 43(5): 830-840.
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Through detailed geochemical analysis of over 40 crude oil, condensate oil and heavy oil samples in the southern margin of Junggar Basin, and based on the hydrocarbon generation condition of five sets of source rocks, with the combination between compositions of carbon isotopes of whole oil, light hydrocarbon, n-alkanes isoprenoids and biomarker’s composition characteristics, a detailed discussion on the source of the condensate oil in anticlines in the middle section of the southern margin was carried out. Condensate oil from the middle section of the southern margin has abundant isoprenoids, Pr/Ph<1.0. Carbon isotopes of whole oil are low with δ13C value between ?27‰ and ?28‰. δ13C value of alkanes with carbon number smaller than 9 ranges from ?26‰ to ?24‰, carbon isotope of C9+ n-alkanes decreases remarkably with increasing carbon number, and the δ13C value of C19+ n-alkanes is lower than ?30‰. The δ13C value of pristane and phytane is lower than ?29‰. The biomarker components contain abundant C27 steranes and C30 methyl steranes, “V” shape distribution of C27, C28 and C29 20R sterane, abundant tricyclic terpanes with dominance of C21, and relatively high content of gammacerane with two isomers. The 20S/(20S+20R) ratio of C29 steranes is between 0.40 and 0.50, and the maturity calculated by the methylphenanthrene index and distribution fraction (Rc) ranges from 0.70% to 1.1%. These geochemical characteristics of the condensate oils are very similar to those mature crude oil of the typical Cretaceous lacustrine source rock in the middle section of Southern Margin, but different from those of typical Jurassic crude oils, implying that these condensate oils are derived from mature Cretaceous lacustrine source rocks instead of highly mature Jurassic coal-measures source rock.
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