23 November 2016, Volume 43 Issue 6
    

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  • Measurement and evaluation of the stress sensitivity in tight reservoirs
    Dou Hongen; Zhang Hujun; Yao Shanglin ; Zhu Dan; Sun Tao; Ma Shiying; Wang Xiaolin
    Petroleum Exploration and Development, 2016, 43(6): 30-31.
    Abstract ( ) Download PDF ( ) Knowledge map Save
    The revised details of SY/T5358—2010 of National Energy Administration Standard from five aspects are put forward, it is aimed at existing flaws of the standard, including measurement procedures, evaluation method and discrimination criteria of the rock stress sensitivity. Terzaghi’s effective stress was derived according to stress equation of Bane and Maximov, which indicates Terzaghi formula, is not only suitable for soil mechanics, but also for rock mechanics. An exponential model of Terzaghi effective stress and rock permeability was built from former researcher’s formula of permeability modulus. The exponential model was used to fit experimental data, with a good accuracy under two different experiment conditions, constant confining pressure (constant-external pressure) and changing-pore-fluid pressure (changing-internal pressure), and constant-pore-fluid pressure (constant-internal pressure) and changing- confining pressure (changing-external pressure). Since constant-external pressure and changing-internal pressure accords with the actual oilfield development, it is recommended to be used in the laboratory operation. It is concluded through the study that the stress sensitivity of reservoir rock can be evaluated with stress sensitivity coefficient α of the exponential model, the stress sensitivity coefficient, 0.005 MPa?1
    Slope belt types and hydrocarbon migration and accumulation mechanisms in rift basins
    Zhao Xianzheng; Jin Fengming; Li Yubang; Wang Quan; Zhou Lihong; Lyu Yanfang; Pu Xiugang; Wang Wei
    Petroleum Exploration and Development, 2016, 43(6): 841-849.
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    Based on the classification of slope belts in rift basins, this paper discusses hydrocarbon accumulation characteristics and accumulation mechanisms of different slopes. The slopes of the Jizhong and Huanghua depressions in the Bohai Bay Basin are classified into five types including flexure slope break, gentle platform slope, wide terrace faulted slope, narrow-steep terrace faulted slope and tilting slope in terms of basement sedimentation, tectonic activities, occurrence and geometric configuration. Each individual slope shows various hydrocarbon accumulation characteristics and enrichment extent caused by different accumulation mechanisms. Flexure slope break is characteristic of terrace fault type of hydrocarbon accumulation with the highest level of hydrocarbon enrichment, while, gentle platform slope, wide terrace faulted slope and narrow-steep terrace faulted slope are characterized by medium enrichment with near-source linear shape, far-source stair shape and fault zone multiple hydrocarbon accumulations, separately. However, tilting slope shows relatively low hydrocarbon enrichment. The hydrocarbon accumulation controlling factors are mainly consisted of nose structure, sandstone development degree, sand body with dominant physical property and juxtaposition thickness. Nose structures control hydrocarbon convergence directions, sandstone development degree controls lateral hydrocarbon migration, sand bodies with dominant physical property control lateral hydrocarbon diversion, and juxtaposition thickness controls hydrocarbon vertical migration.
  • Assessment of global unconventional oil and gas resources
    Wang Hongjun; Ma Feng; Tong Xiaoguang; Liu Zuodong; Zhang Xinshun; Wu Zhenzhen; Li Denghua; Wang Bo; Xie Yinfu; Yang Liuyan
    Petroleum Exploration and Development, 2016, 43(6): 850-862.
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    This paper evaluates the recoverable unconventional oil and gas resources around the world, reveals main controlling factors and potential regions for the rich accumulation of unconventional oil and gas, and standardizes the classification of seven types of resources (i.e., heavy oil, oil sand, tight oil, oil shale, shale gas, tight gas, and coalbed methane). By virtue of commercial databases for global petroliferous basins, together with single-well data packages in North America and basic data of exploration and development of Chinese companies in unconventional oil and gas resources blocks around the world, contour maps of abundance for global recoverable resources are formed through spatial graphic interpolation of key assessment parameters of seven types of unconventional oil and gas resources on the Geographic Information System (GIS) platform, which systematically evaluate the potential of seven types of unconventional oil and gas resources. The assessment reveals: (1) These seven types of resources around the world are distributed predominantly in 476 formations in 363 petroliferous basins. (2) Total recoverable unconventional oil and gas resources in the world are respectively 442.1 billion tons and 227 trillion cubic meters. (3) Unconventional oil and gas resources can be divided into “source-bound type” and “strata-bound type”. The “source-bound type” resources are mainly controlled by 6 groups of high-quality source rock around the world, among which, the tight oil and gas resources are featured by the “integration of reservoir and source”, presenting the best prospect for the development and application, and the “strata-bound type” oil sand and heavy oil resources, controlled by the transformation of the late structure, are mainly distributed in the slope belt of the Mesozoic-Cenozoic basins, presenting a good prospect for the resource development and application in the shallow layers. (4) Besides hot spots in North America, tight oil in the West Siberia Basin and the Neuquen Basin as well as heavy oil in the Arab Basin will become potential targets for the development of unconventional oil and gas resources in the future.
  • Play types, geologic characteristics and exploration domains of lithological reservoirs in China
    Tao Shizhen; Yuan Xuanjun; Hou Lianhua; Zhu Rukai; Yang Fan; Li Changwei; Wang Lan; Zhang Guosheng; Wang Ying; Sun Guoxin; Wei Yanzhao
    Petroleum Exploration and Development, 2016, 43(6): 863-872.
    Abstract ( ) Download PDF ( ) Knowledge map Save
    By dissecting thirty-six representative oil-gas reservoirs and analyzing accumulation conditions of giant oil and gas provinces in four prototype basins, including the Songliao Rift and Depression Basin, the Mesozoic Ordos Depression Basin, the Bohai Bay Rift and Depression Basin, the Mesozoic Junggar Depression Basin, the West Sichuan Foreland Basin and the Tarim Craton Basin, the hydrocarbon plays classification scheme of lithological reservoirs is established and improved from the perspective of oil-gas accumulation zone and exploration area selection. The results revealed the accumulation characteristics and controlling factors of lithological reservoirs of multiple origins in three kinds of slopes, three kinds of sag centers and three kinds of hydrocarbon accumulation assemblages. Based on the understandings on reservoir formation mechanisms and enrichment regularities of different hydrocarbon provinces, six major assessment indexes, parameter system and grading standard of lithological plays are established, including hydrocarbon source rock condition, transportation pathway, reservoir condition, reservoir-cap assemblage, fluid property, and time-space configuration etc. Through comprehensive analysis of burial history, hydrocarbon-generation history, digenesis history, tectonic history, trap-forming history and accumulation history, plays of lithological reservoirs are evaluated and optimized. The results show the middle-shallow layers in the slope zones of the Songliao and Bohai Bay Basins oil-rich sags, the Mesozoic in the Ordos Basin, the Permian-Jurassic in the Junggar Basin, etc. are the major oil exploration areas in the future, with oil resources of about 42×108 t–67×108 t; the deep volcanic rocks of the Songliao Basin, the Carboniferous of the Junggar Basin, the Cambrian of the Tarim and Sichuan Basins, the Permian-Triassic reefs and shoals within the platform and on the platform margin of the Sichuan Basin are the major gas exploration areas in the future, with the gas resources of about 1.5×1012 m3–2.0×1012 m3.
  • New research progress of Jurassic tight oil in central Sichuan Basin
    Yang Yueming; Yang Jiajing; Yang Guang; Tao Shizhen; Ni Chao; Zhang Bin; He Xiaodong; Lin Jianping; Huang Dong; Liu Min ; Zou Juan
    Petroleum Exploration and Development, 2016, 43(6): 873-882.
    Abstract ( ) Download PDF ( ) Knowledge map Save
    The resource potential, “fractured” reservoir, reservoir type and stimulation technology of Jurassic tight oil in central Sichuan basin were investigated. Based on the evaluation method of tight oil resource, the amount of oil resources of the five Jurassic layers were estimated at 1.6 billion tons, showing that the Jurassic oil resource potential in central Sichuan Basin is huge. Integrated analysis of static and dynamic data including core-description, thin section examination, well test and exploration show Jurassic reservoirs are fracture-pore reservoir with ultra-low porosity, super-low permeability, rather than single “fractured” reservoir believed before. Jurassic reservoirs are tight oil reservoir with the characteristics of near source charge and continuous distribution. The high-quality hydrocarbon source, reservoir with better physical properties and fracture are the main factors controlling tight oil enrichment. “Horizontal well + volume fracturing” of Shayi Member tight sandstone reservoir and the “horizontal well + fracture acidizing” for the Da’anzhai Member shell limestone reservoir have achieved good stimulation effect.
  • Structure modeling of the Maui Gas Field, Taranaki Basin, New Zealand
    Akm Eahsanul Haque; Md. Aminul Islam; Mohamed Ragab Shalaby
    Petroleum Exploration and Development, 2016, 43(6): 883-892.
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    3D seismic and well log dataset were used jointly to build a structural model of the Late Cretaceous to Pliocene sedimentary sequence in the Maui Gas Field, to predict structural mechanics in the Taranaki Basin with geostatistics. Three phases of tectonic movements affected by faulting in this field were identified by this structural model: Late Cretaceous to Palaeocene rifting phase, Late Eocene to Miocene compressive faulting phase, and Plio-Pleistocene differential (compressive faulting in Maui South, normal fault activity in Maui North) faulting phase. Different phases of tectonic movements resulted in different structural patterns, Early Oligocene formations have abundant normal faults with slight slip and higher dip angles (40??70?), and lower dip angle in the north (10??15?) than in the south (15??20?); Mid-Oligocene to Late Miocene formations contain low angle reverse faults (20??40?), showing the structures in this period were affected by compressive stress on the whole; structural inversion occurred during mid-Oligocene to Pliocene, indicating the structural stress was contraction first and extension later in this period.
  • Discovery of Xuanhan-Kaijiang Paleouplift and its significance in the Sichuan Basin, SW China
    Gu Zhidong; Yin Jifeng; Jiang Hua; Li Qiufen; Zhai Xiufen; Huang Pinghui; Peng Ping; Yang Fan ; Zhang Hang
    Petroleum Exploration and Development, 2016, 43(6): 893-904.
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    A large inherited paleouplift from pre-Sinian to Early Cambrian, named Xuanhan-Kaijiang paleouplift, has been discovered based on multiple geological information in the eastern Sichuan Basin: firstly, onlap deposition of Upper Sinian Dengying Formation and Lower Cambrian is observed from peripheral zone to central Xuanhan-Kaijiang area from the seismic profile; secondly, Dengying Formation thickness distribution map shows that this formation is thinnest in Xuanhan-Kaijiang area, and thickens towards the surrounding areas; thirdly, terrigenous clastic rock is observed in Upper Sinian Dengying Formation on outcrops in Chengkou County and Wuxi County etc., indicating the development of a paleouplift. The analysis of the characteristics, formation and evolution of the paleouplift reveals that the plane distribution of the paleouplift shows an arched structure, stretching in a north-south trend. The area of the paleouplift is around 16 000 km2. Vertically, the paleouplift can be divided into three parts: platform in the middle, steep slope in the west and ramp in the east. Originally, the paleouplift was an erosion-type uplift above the water level during the early stage of the Late Sinian; and gradually transformed into deposition-type uplift under water level during the late stage of the Late Sinian to the Early Cambrian. The formation of the paleouplift was controlled by several factors, including basement uplift, intracratonic rift, basement faults and regional uplifting. The paleouplift and its slope areas, favorable for the development of high energy facies and karst weathering reservoirs, are important exploration target areas in the eastern Sichuan basin in the near future.
  • The characteristics of Precambrian sedimentary basin and the distribution of deep source rock: A case study of Tarim Basin in Neoproterozoic and source rocks in Early Cambrian, Western China
    Wu Lin; Guan Shuwei; Ren Rong; Wang Xiaobo; Yang Haijun; Jin Jiuqiang; Zhu Guangyou
    Petroleum Exploration and Development, 2016, 43(6): 905-915.
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    Based on outcrops of the whole basin, drilling and seismic data, this paper makes a systematic analysis of Neoproterozoic basin stratigraphic distribution and tectonic evolution characteristics in Tarim. Under the control of the aggregation and breakup of Rodinia supercontinent, the extensional sedimentary basin formed with North-South differences in the Neoproterozoic, separated by the middle ancient land. There is a sedimentary basin in the north, east-west banded, with two thickness centers, Aksu region in northwest and Manjiaer-Kuruketage region in northeast and maximum thickness about 2 500-3 500 m. There are two sedimentary basins in the south, north-east banded, with two thickness centers, Yecheng and Hetian with maximum thickness about 1 500-2 000 m. The evolution of the basin can be divided into two stages, rift in Nanhuan and depression in Sinian, the latter stage deposits larger range but with thinner thickness of strata. Its main rock types contain volcanic rock, clastic rock, moraine rock and carbonate rock. The distribution of source rock during Early Cambrian period is mainly controlled by the development characteristics of the Neoproterozoic sedimentary basin.
  • Origin of structurally controlled hydrothermal dolomite in epigenetic karst system during shallow burial: An example from Middle Permian Maokou Formation, central Sichuan Basin, SW China
    Liu Hong, ; Ma Teng; Tan Xiucheng, ; Zeng Wei; Hu Guang, ; Xiao Di; Luo Bing; Shan Shujiao ; Su Chengpeng
    Petroleum Exploration and Development, 2016, 43(6): 916-927.
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    Based on the outcrops, drilling cores, thin sections observation and geochemical analysis, studies were done on the genesis of dolomite in the Middle Permian of central Sichuan Basin. Mosaic fine-crystalline dolomite and subhedral-enhedral siliceous fine-crystalline dolomite can be identified microscopically, which have different geochemical characteristics. Genetic analysis indicates insufficient mantle-derived fluids and marine-derived fluids entered karst system through basement faults, and then were mixed with previously-preserved crust-derived fluids in varied degrees during early Longtan period; in the relatively porous karst system, carbonate sands were dolomitized to subhedral-enhedral dolomites; insufficient mantle-derived hydrothermal fluids were mixed with previously-preserved crust-derived fluids, with coincidence reconstruction on the regions where there were preexisting karst systems but short of hydrothermal fluids, resulting in precursor limestone breccias and host rocks dolomitized to form anhedral mosaic dolomite; during late Longtan period, the overlying sediments sealed the epigenetic karst systems, and the insufficient deep mantle-derived fluids were mixed with previous fluids within the karst systems, with coincidence reconstruction on the relatively porous dolomites, while the tight anhedral mosaic fine-crystalline dolomites didn’t change much, forming two types of dolomites with different petrological and geochemical characteristics. Thus, the formation of preferable dolomite reservoir is possibly related to inland facies-controlled epigenetic karst, and therefore the exploration of Maokou Formation in Middle Permian should pay more attention to the karst-related reservoirs.
  • Geological characteristics of source rock and reservoir of tight oil and its accumulation mechanism: A case study of Permian Lucaogou Formation in Jimusar sag, Junggar Basin
    Qiu Zhen, ; Shi Zhensheng; Dong Dazhong, ; Lu Bin; Zhang Chenchen; Zhou Jie; Wang Hongyan; Xiong Bo; Pang Zhenglian; Guo Hekun
    Petroleum Exploration and Development, 2016, 43(6): 928-939.
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    The source rocks and reservoirs in the Middle Permian Lucaogou Formation of Jimusar sag, Junggar Basin, NW China and its source-reservoir assemblages were studied to reveal accumulation mechanism of the tight oil, on the basis of core observation, thin slice identification, X-ray diffraction analysis, TOC test and rock pyrolysis test of source rock samples, and mercury injection and nuclear magnetic resonance of reservoir samples, combined with burial history and hydrocarbon-generating history of source rocks. It is concluded that the Lucaogou Formation source rocks mainly have typeⅠandⅡorganic matter, with an average TOC of 4.6%, indicating they are high-quality source rocks in low mature - mature stage; and they can be divided into three types, shale, mudstone and silty mudstone. The reservoir rock in Lucaogou Formation features low porosity and low permeability; mercury injection and NMR (nuclear magnetic resonance) tests show that nano-scale pores and throats (with radius of 50-500 nm) constitute the main reservoir space, and the reservoirs can be classified into three types, muddy siltstone, dolomitic siltstone, and dolarenite according to lithology. The source rocks and reservoirs alternate with each other in vertical direction and are distributed continuously in lateral direction, and the source rocks have been generating oil and gas constantly. It is concluded through comprehensive analysis that since the Late Jurassic, the source rocks in Lucaogou Formation have been generating oil continuously and massively, causing high pressurization, and providing constant driving force and oil supply, as a result, the oil has been charged into the tight reservoirs effectively and continuously, forming abundant tight oil resources.
  • A seismic quantitative identification method of slope break belt
    Zhou Lu, ; Yuan Bing; Song Yong; Wu Yong; Kong Yuhua; Zhou Jieling; Ma Teng
    Petroleum Exploration and Development, 2016, 43(6): 940-948.
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    Based on the slope variation characteristics of slope break belt and slope theory in geomorphology, a method, which can quantitatively identify the slope break belt based on the precise seismic horizon data and slope and aspect attribute, was established, and the mathematic surface model, dip logging, seismic attributes, and formation thickness contours were used to verify this method. Then, this method was used to quantitatively identify the distribution range and geometric parameters of the slope break belt in the Lower Cretaceous Qingshuihe Formation in Chepaizi area of Junggar Basin, NW China, the results show that the formation slope calculated by this method is consistent with that reflected by the dip logging data, the distribution range of the slope break belt identified by this method is in line with the trend of the formation thickness and the distribution range of the discovered stratigraphic-lithologic reservoir, and the slope attribute is better than formation dip attribute in identifying the slope break belt. The geometric parameters of the slope break belt which this method can identify are the accurate location of slope break and slope toe, the value of the slope and the height difference and width between the slope break and slope toe.
  • Progress in key technologies for evaluating marine shale gas development in China
    Jia Ailin; Wei Yunsheng; Jin Yiqiu
    Petroleum Exploration and Development, 2016, 43(6): 949-955.
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    The Lower Paleozoic Longmaxi and Qiongzhusi Formatiion shale plays were taken as research objects to summarize the geologic and reservoir characteristics of marine shale gas in China. Based on the theory and technology achievements made during the twelfth five-year plan, a key index system was established to evaluate shale gas well production effect in China, and a comprehensive classification was consequently presented by integrating geological statistical indexes and economic evaluation indexes; to characterize the complex fracture network formed by fracturing, a generalized analytical model was established by incorporating fractal and continuum geometry theory to capture the transient behavior of such fractured horizontal well throughout production life. An associated probabilistic analysis, based on the Monte Carlo simulation was presented by linking a probabilistic worksheet with the analytical model, and then used to determine a range of possible outcomes (i.e., EUR, decline rate and production time). Meanwhile, an optimization approach for development parameters, including fractured horizontal segment, fracture geometry (i.e., fracture length, conductivity, number), well spacing and drawdown management was advanced. There are still many unresolved problems on geologic theory, flow mechanism and productivity evaluation method, development technical policy and economic benefits, which limit large-scale and high-efficiency exploitation of shale gas resource in China.
  • A method of production profile quick prediction based on typical curves: A case study of the Upper Shale large multi-layered sandstone reservoir, Rumaila Oilfield, Iraq
    Li Yong; Li Baozhu; Tian Changbing; Zhu Yixiang; Song Benbiao; Qian Qihao
    Petroleum Exploration and Development, 2016, 43(6): 956-960.
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    According to the advantages of numerical simulation and conventional reservoir engineering methods, in consideration of reservoir heterogeneity and changes in development mode, a method of production performance quick prediction based on typical curves was proposed in this study. In this method, fine reservoir simulation is conducted based on the fine geological model of the large sandstone reservoir, and typical curves of different reservoir types under different development modes are generated; then based on results of reservoir type classification for all layers, geologic reserve evaluation result, well productivity and injectivity evaluation, production profile, the production indexes of the whole field can be predicted. The reliability of the new method was verified by the large multi-layered sandstone reservoir, Upper Shale reservoir in Rumaila Oilfield. The new method can reach prediction accuracy similar to conventional numerical simulation method, and takes shorter time.
  • Combining nuclear magnetic resonance and rate-controlled porosimetry to probe the pore-throat structure of tight sandstones
    Xiao Dianshi, ; Lu Shuangfang; Lu Zhengyuan; Huang Wenbiao; Gu Meiwei
    Petroleum Exploration and Development, 2016, 43(6): 961-970.
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    Rate-controlled porosimetry (RCP), nuclear magnetic resonance (NMR) and micro CT tests were conducted on five tight sandstone samples, the results were compared to reveal the limitations of RCP in determining the pore size distribution (PSD) and pore to throat ratio (PTR), and then an effective method to test the pore-throat structure of tight sandstone by combining NMR and RCP was proposed. The quasi-PSD derived by RCP was bimodal, the left peak of which corresponding to throats was in good agreement with that of NMR, while the right peak corresponding to pore bodies had similar volume content and different distribution range with that of NMR. RCP reflected an equivalent spherical radius of pore body, and the calculation was significantly larger than the maximum inscribed radius (MIR) of the actual pore body with the same volume; whereas in NMR, the ratio of pore volume to surface area was used to estimate pore radius, and the pore radius calculated was close to MIR. The full-range pore body size distribution was determined by substracting the RCP-derived throat size distribution from NMR-derived PSD, and then the pore throat connectivity was evaluated comprehensively. The mean value of PTR calculated by RCP was larger than 100.0 due to the differences in the calculation method between pore body size and throat size in RCP, while the mean value of PTR calculated by combining NMR and RCP ranged from 7.5 to 64.0. It is concluded that the combination of RCP and NMR experiment is an effective way to comprehensively reveal the distribution of pore and throat sizes in tight sandstone.
  • Numerical simulation of chemical potential dominated fracturing fluid flowback in hydraulically fractured shale gas reservoirs
    Wang Fei; Pan Ziqing
    Petroleum Exploration and Development, 2016, 43(6): 971-977.
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    To find out the impact of chemical potential difference between the low salinity fracturing fluid and the high salinity formation water on fracturing fluid flow back, a chemical potential difference expression of fracturing fluid and formation water was deduced, on this basis, a mathematical model which considers viscous force, capillary force and osmosis pressure matrix with fracturing gas-water flow was built, the flow back performance of fracturing fluid driven by chemical potential difference was simulated, and the formation water saturation and salt concentration profile with flow back time were analyzed. The results show that in the process of flow back, the water molecules in the matrix driven by the chemical potential difference continually migrated to the deeper reservoirs, while salt ions in the matrix constantly spread to the fractures. After 168 h of fracturing-fluid flow back, the migration distance of water was up to 40 cm, and the salt concentration near the fracture surface increased by 0.841%, and the cumulative flow back rate of the gas well was only 22.1%. The cumulative flow back rate would be 23.5%, 32.4% and 41.1% respectively, without taking into account the effect of gas absorption, chemical osmosis or capillary imbibitions. The capillary imbibitions and chemical osmosis seriously hindered the fracturing-fluid flow back, therefore, the two factors should be fully considered in the post-fracturing evaluation of shale gas wells.
  • Shale gas sweet spot identification and precise geo-steering drilling in Weiyuan Block of Sichuan Basin, SW China
    Liu Naizhen; Wang Guoyong
    Petroleum Exploration and Development, 2016, 43(6): 978-985.
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    Based on drilling and production test data and the geological, geochemical, geophysical and rock mechanics achievements of Weiyuan Block of Sichuan Basin, “sweet spots” of shale gas were determined and geosteering technology was tested in drilling the sweet spots under complex structural background. The high quality Silurian Longmaxi Formation shale (with TOC≥2%) in the study area, thick (36.0?44.5 meters), is divided into four sublayers, from bottom to top, which differ widely in TOC (2.0%?8.1%), gas content (1.2?12.6 m3/t), porosity (0.66%?11.80%), and brittle mineral content (17.5%?98.5%). Considering gas content and fracability of shale, the layer Long 11a in Longmaxi Formation is the best “sweet spot” layer in vertical direction; horizontally, the areas with folding structure in shale reservoir have more natural fractures, and thus have better storage quality and permeability, are “sweet spots”. During drilling of the sweet spots, three-dimensional seismic and geological modeling was used to predict the depth of “sweet spot”, which was corrected in time with drilling data, and by controlling well trajectory this way, the drilling rate of “sweet spots” has been improved.
  • Rheological properties of Aphron based drilling fluids
    Khamehchi Ehsan; Tabibzadeh Shahin; Alizadeh Ali
    Petroleum Exploration and Development, 2016, 43(6): 986-990.
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    A new drilling fluid system has been successfully used to drill depleted reservoirs which are known as Aphron based drilling fluids. The rheological behavior of the Aphron based drilling fluid was investigated by experimental tests and data analyses. After generating a typical Aphron based drilling fluid, its viscosity was tested at different temperatures, and the test data was fitted using Power law, Bingham Plastic and Herschel-Bulkley models. It is found that Herschel-Bulkley model is more accurate to describe flow properties for fluids before and after Aphron generation process for all temperatures. Based on Herschel Bulkley model, the shear thinning ability of the fluid increases by increasing temperature, the gel strength and hole cleaning capacity of the fluid increase after Aphron generation, and increasing temperature to high value will not debilitate Aphron drilling fluid performance significantly. The fluid has high viscosity in low shear rate conditions, so that it can provide a strong seal in pore openings to bridge the pores. Aphron bubble growth rate over the time and drainage rates are determined as criteria for Aphron bubble stability. Bubble size growth rate is very low and the longevity is long, and liquid drains in a weak rate in drainage static test, which shows a strong stability of the Aphron based drilling fluid.
  • Screen sand retaining precision optimization experiment and a new empirical design model
    Dong Changyin; Zhang Qinghua; Gao Kaige; Yang Kangmin; Feng Xingwu; Zhou Chong
    Petroleum Exploration and Development, 2016, 43(6): 991-996.
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    In the design of sand retaining precision, the existing design methods consider unilateral factors or have limited applicability. A series of experimental tests for screen sand retaining precision optimization were performed. An empirical model was worked out by experiment results fitting. The experimental tests were performed using screen evaluation experimental apparatus with 35 types of formation sand samples and 9 types of screen samples. For all sand samples with different sizes, the optimum sand retaining precisions were determined by calculating the sand-passed ratios and flow capacity index under different sand retaining precisions. The experiment results were fitted, and a new model was put forward to design reasonable screen precision for a given formation sand, considering the median size, the characteristic size of fine composition and uniformity coefficient of the sand and real production condition. The model has been applied in more than 20 wells and the effect is very good. The model considers most important factors affecting sand control effect and has excellent adaptability. And the model provides an effective method to optimize the screen precision without the need of performing lots of experiment tests and is easy to be used.
  • Hydrodynamic response for flexible connectors of mobile offshore base at rough sea states
    Wu Linjian, ; Wang Yuanzhan, ; Xiao Zhong, ; Li Yi
    Petroleum Exploration and Development, 2016, 43(6): 997-1004.
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    Mobile offshore base (MOB) was treated as a research object, and a simplified algorithm was developed for determining the dynamic constraint forces on flexible connectors of MOB at rough sea states. The algorithm was adopted to calculate and analyze the fluctuation laws between dynamic constraint forces and different parameters. The wave loads on MOB structures were evaluated based on the revised Morison equation instead of potential flow theory, and the conventional computational methods were simplified. The numerical results of the simplified algorithm were compared to those of the algorithm based on potential flow theory for validating the correctness and reasonability of the simplified algorithm. The simplified algorithm was used to estimate the dynamic constraint forces on flexible connectors of MOB under different sea states, wave incident directions, and connector stiffness values. The results show as the wave angle increases, the dynamic constraint force decreases in the x direction, while increases first and then decreases in the y and z directions; the dynamic constraint force increases as the sea state increases, and shows a trend of linear increasing with the connector stiffness increasing; the dynamic forces on different connectors are well even in the same conditions.
  • An enhanced thermo-actuated shape memory polymer composite coupled with elastomer
    Tong Zheng; Pei Xiaohan; Shen Zejun; Wei Songbo; Gao Yang; Huang Peng; Shi Bairu; Sun Fuchao; Fu Tao
    Petroleum Exploration and Development, 2016, 43(6): 1005-1013.
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    A new enhanced thermo-actuated shape memory polymer (SMP) composite PE-NBR was developed and its properties were compared with traditional SMPs. The numerical simulation and experiment study on packer element were performed by the way of newly developed constitutive model. The functional composite system with shape memory effect is mainly composed of polyolefin acting as shape memory component and particle-filled elastomer acting as modified enhancement component. The PE-NBR system has advantages over traditional SMP with tensile strength of 14.3 MPa, hardness of 71 and shape recovery ratio of 95%. The ratio of polyolefin in the system can be adjusted from 20% to 90% and that of elastomer can be adjusted from 10% to 70%. The constitutive model with rubber plastic blending for PE-NBR system based upon mesomechanics and macroscopic properties of materials is used to meet the numerical study requirements of large-deformation, temperature-dependence and nonlinear composites. The rating pressure of packer element using PE-NBR system is more than 10 MPa and the maximum of contact pressure is obtained in the location which is 60 mm away from the end surface of the element.
  • Application of nanotechnology in petroleum exploration and development
    Liu He; Jin Xu; Ding Bin
    Petroleum Exploration and Development, 2016, 43(6): 1014-1021.
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    Combined with the actual demand of oil and gas exploration and development, this paper summarizes the research progress and application of nanotechnology in various fields of petroleum exploration and development, discusses and prospects the application and development of nanotechnology in the future. Nano characterization technology has played an important role in the analysis of the mineral composition, micro pore structure and rock physical properties of unconventional reservoirs; the reservoir nano sensor is still in the laboratory stage, and the reservoir nano robots still need a key technology breakthrough; the oil and gas migration numerical simulation technology in micro-nano porous media will become an important means of researching unconventional oil and gas migration mechanism, distribution pattern and resource evaluation; nano materials have the size and surface effect, wetting characteristics, inhibition characteristics of particle migration, shear thickening behavior, nanometer photocatalytic properties, nano filtration and nano corrosion and wear resistance, then have broad application prospects in the fields of enhanced oil recovery, water treatment, engineering anti-corrosion. The future development directions of nanotechnology are in the three aspects, nano characterization and numerical simulation, nano sensing and nano materials. In-situ modification of low grade oil and gas resources and synthesis of oil and gas by nano photosynthesis are the two potential development directions.
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