23 August 2016, Volume 43 Issue 4
    

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  • Geological difference and its significance of marine shale gases in South China
    ZHAO Wenzhi, LI Jianzhong, YANG Tao, WANG Shufang, HUANG Jinliang
    , 2016, 43(4): 499-510. https://doi.org/10.11698/PED.2016.04.01
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    Organic-rich marine shales are developed in both the Cambrian Qiongzhusi Formation and the Ordovician Wufeng Formation-Silurian Longmaxi Formation in South China, but are different in the drilling results of shale gas exploration. Comparing the differences in shale gas formation conditions between Qiongzhusi and Wufeng-Longmaxi has practical and theoretical significance. This study reveals: (1) in the Sichuan Basin, the Wufeng-Longmaxi Formation has slightly higher TOC than the Qiongzhusi Formation, whereas Qiongzhusi Formation has some local high TOC areas outside of the Sichuan Basin; (2) the Qiongzhusi Formation has much higher thermal evolution degree than the Wufeng-Longmaxi Formation; (3) with undeveloped organic pores, the Qiongzhusi Formation has a 1/3 to 1/2 porosity of the Wufeng-Longmaxi Formation; (4) Qiongzhusi shale has a lower gas content, only 1/2 of that in Wufeng- Longmaxi shale; (5) the Qiongzhusi Formation is mainly composed of siliceous shale and the silica is hot water origin, whereas the Wufeng-Longmaxi Formation consists mainly of calcareous siliceous shale and the silica is biogenic origin; (6) the Wufeng-Longmaxi Formation has overpressure, while the Qiongzhusi Formation is normal in pressure. The reasons for the differences are: (1) different sedimentary environments affect TOC and shale thickness; (2) the Qiongzhusi Formation is over-mature, which caused depletion of hydrocarbon generation, organic carbonization, porosity reduction, and gas content drop; (3) the bad roof and floor conditions of the Qiongzhusi Formation are not good for shale gas preservation; (4) Wufeng-Longmaxi Formation is located in the slope and syncline accompanied with overpressure, and is in favor of preservation and high production of shale gas; (5) the uranium content in the Qiongzhusi Formation is twice that of the Wufeng-Longmaxi Formation, which is the main reason of its higher thermal evolution degree. It is concluded that shale gas enrichment in the marine shale in South China requires favorable geological conditions: organic-rich intervals, moderate thermal evolution, rich organic pores, high gas content, good roof and floor preservation conditions, and moderate burial depth. The Wufeng-Longmaxi Formation has better shale gas enrichment conditions and higher resource potential, whereas the Qiongzhusi Formation has poorer shale gas accumulation conditions and limited favorable areas.
  • Exploration potential of shale oil in Chang7 Member, Upper Triassic Yanchang Formation, Ordos Basin, NW China
    YANG Hua, NIU Xiaobing, XU Liming, FENG Shengbin, YOU Yuan, LIANG Xiaowei, WANG Fang, ZHANG Dandan
    , 2016, 43(4): 511-520. https://doi.org/10.11698/PED.2016.04.02
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    The geological conditions and exploration potential of shale oil in Chang7 Member, Upper Triassic Yanchang Formation, Ordos Basin, were studied from various aspects, including petrographic characteristics, storage ability, geochemical features, friability and mobility of hydrocarbon in the source rock, etc. A classification criterion of lithofacies for Upper Triassic Chang 7 source rock in Ordos Basin were established based on the correlation between lithology, organic carbon content and logging parameters, from which, the spatial distribution and development scale of two types of shale, black shale and dark massive mudstone, have been predicted. Qualitative and quantitative characterization of the micro-structures of Chang7 source rock using state-of-the-art microscopic facilities including argon ion milling - field emission scanning electron microscopy (FESEM), focused ion beam scanning electron microscopy (FIB-SEM) and Nano-CT reveal that the dominant pore types in Chang7 source rock are intra-granular pores and inter-granular pores; the pores and throats in the two kinds of lithofacies are both nano-scale, and the dark massive mudstone has better physical properties than the black shale. The Chang7 shale oil resources and mineability were evaluated based on the parameters from geochemical experiments on the source rock, including pyrolysis S1, chloroform bitumen ‘A’, TOC and thermal maturity, free hydrocarbon content, as well as geo-mechanical properties such as brittle mineral content and development of fractures. With large scale of favorable lithofacies, good storage ability and abundant hydrocarbon, Chang7 Member has the material basis for shale oil occurrence and accumulation, in addition, the shale oil there has accumulated greatly and has favorable properties for flowing in nano-scale pores and throats. All these show that Chang7 Member has high potential for shale oil exploration, in which, the dark massive mudstone is a more favorable target for shale oil exploration under the present technical conditions.
  • The axial channel provenance system and natural gas accumulation of the Upper Miocene Huangliu Formation in Qiongdongnan Basin, South China Sea
    XIE Yuhong, LI Xushen, FAN Caiwei, TAN Jiancai, LIU Kun, LU Yi, HU Wenyan, LI Hu, WU Jie
    , 2016, 43(4): 521-528. https://doi.org/10.11698/PED.2016.04.03
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    Based on the data of regional outcrop observation, high-precision 3-D seismic detection and wellbore rock-electricity, this paper researched macro-water distribution, seismic architecture of sedimentary-filling, rock composition, heavy mineral assemblage, and zircon age. The axial channel provenance system and accumulation of natural gas of the Upper Miocene Huangliu Formation in the Qiongdongnan Basin was analyzed. The research showed that axial channels deposits were provided with two depression stages, multiple provenances, and gravity flows by bottom current rework. Early channels sandstone with small size and formation overpressure was mainly from terrigenous material of southwest drainage system in Hainan uplift, while Qiupen River in the central Kunsong uplift was the primary provenance of late channels sandstone with large scale of sediments, good continuity and normal formation pressure. There are three types of axial channel sandstone traps: litho-stratigraphic, lithologic and tectono-stratigraphic trap. Natural gas of early channels was driven by deep overpressure and vertically migrated into reservoir along fissures, while natural gas of late channels lateral migrated from west to east.
  • Mechanism of sand body prediction in a continental rift basin by coupling paleogeomorphic elements under the control of base level
    DONG Guiyu, HE Youbin
    , 2016, 43(4): 529-539. https://doi.org/10.11698/PED.2016.04.04
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    In view of the complex sandbody distribution in continental rift basins, a sandbody prediction method is proposed based on the coupling of three core paleogeomorphic elements, provenance system, channel system, and slope break system, which composes the process of “provenance-transport-sedimentation” controlled by base level. The sand body prediction method takes the base level as the lever, the equilibrium position near the lake basin edge as the supporting point, and the core paleogeomorphic elements as study objects, lays stress on the fact that dynamic factors controlling static factors, and takes full consideration of flow state conversion and sandbody genesis. The core paleogeomorphic elements have eight types of theoretical coupling modes, corresponding to coupling deposition effect from the worst to the optimal. During fluctuations of base level, the coupling modes of the core paleogeomorphic elements in continental rift basins change under the “seesaw effect”, as a result, the migration pattern, sedimentary environment, and genesis of sand body change significantly, which control sand body distribution in turn. The sand body development regularity of the Gaoyou Sag in Northern Jiangsu Basin and the Weixinan Sag in Beibu Gulf Basin has been analyzed based on this sand control mechanism and a good prediction result of sand body is achieved, which confirms the validity and practicality of the sand control mechanism.
  • Lower Paleozoic source rocks and natural gas origins in Ordos Basin, NW China
    LIU Dan, ZHANG Wenzheng, KONG Qingfen, FENG Ziqi, FANG Chenchen, PENG Weilong
    , 2016, 43(4): 540-549. https://doi.org/10.11698/PED.2016.04.05
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    Based on the geochemical characteristics of Lower Paleozoic gases from 154 most recently drilled wells and their genetic type, in combination with the organic abundance evaluation of 733 core samples from the Lower Paleozoic, the origin of Lower Paleozoic gases in Ordos Basin was discussed. According to the carbon isotope data of paraffin gases in the gas samples and the geological background, the Lower Paleozoic gases are divided into three types and four sub-types: (1) the coal-derived gas generated from the Upper Paleozoic coaly source rock; (2) the oil-associated gas sourced from the Lower Paleozoic source rock, and (3) the mixing gas originated from the Upper Paleozoic coaly source rock and Paleozoic limestone, and the mixing gas can be divided into two sub-types, the mixing gas of positive carbon isotopic series and that of negative carbon isotopic series. From the TOC and organic maceral results of Lower Paleozoic source rock, the samples below salt have an average TOC of 0.3%, with 28.2% of them having TOC>0.4%, the kerogen type being sapropel type, showing great gas generating potential. The Lower Paleozoic gases are primarily coal-derived gas generated from the Upper Paleozoic coal, some oil-associated gas of self-source and self-reservoir can be found in pre-salt reservoirs in the central-eastern basin, where the developed source rock can serve as the source of some Lower Paleozoic gas.
  • Quantitative analysis of the effect of salt on geothermal temperature and source rock evolution: A case study of Kuqa foreland basin, Western China
    WU Hai, ZHAO Mengjun, ZHUO Qingong, LU Xuesong, GUI Lili, LI Weiqiang, XU Zuxin
    , 2016, 43(4): 550-558. https://doi.org/10.11698/PED.2016.04.06
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    There develop two sets of thick salt in the Kuqa foreland basin, the impact of salt thickness on geothermal temperature and thermal evolution of source rock was analyzed using transient thermal modeling method based on the two dimensional seismic profile from west to east of the basin and the related boundary condition. The results indicate that: (1) the change of salt plies will not have different impact on geothermal temperature when the total thickness of the salt body is constant; (2) the geothermal temperature of formations above the gypsum will increase about 0.3-0.6 ℃/100 m, while the subsalt geothermal temperature will decrease about 0.6-1.0 ℃/100 m in the west of the basin; the geothermal temperature of formations above the salt will increase about 1.9-2.3 ℃/100 m, while the subsalt geothermal temperature will decrease about 0.2-2.6 ℃/100 m in the east of the basin; (3) the value of vitrinite reflectance will be lagged about 0.02%/100 m averagely in the west of the basin, and will be lagged about 0.05%/100 m in the east. As the thermal conductivity of gypsum-salt rock is negatively correlated with temperature, the salt body in the east has a shallower burial and lower geothermal temperature, so its overall thermal conductivity is higher, causing the changing rates of geothermal temperature and Ro are higher than the west. A case study of Dina 2 condensate field of Kuqa foreland basin indicates that the charge time of hydrocarbon there lagged about 7.5-9.0 Ma because of the delayed source rock thermal evolution caused by the salt, matching well with the formation period of trap, which is favorable for the late accumulation of hydrocarbon in this area.
  • Physical properties modeling of reservoirs in Mansuri oil field, Zagros region, Iran
    ALI Dashti, EBRAHIM Sefidari
    , 2016, 43(4): 559-563. https://doi.org/10.11698/PED.2016.04.07
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    The porosity and permeability distribution in four layers of the Cretaceous Ilam Formation was simulated using optimized artificial intelligent algorithms based on conventional logging data of 50 wells in Mansuri oil field in Iran. First, the neutron porosity, interval transit time and density wireline logs in five key wells with core data were used as input parameters to calculate porosity and permeability of the reservoirs using backpropagation artificial neural network (BP neural network) and Support Vector Regression methods, and based on the correlation between the calculated results and the core tested results, BP neural network method was taken to do the physical property calculation. Then, the porosity and permeability distribution of the four layers were modeled using kriging geostatistical algorithms. The results show that Layers 2.1 and 2.2 are high in porosity, Layers 1, 2.1 and 2.2 are high in permeability, while Layer 3 is not reservoir; and the porosity and permeability are higher in the north and lower in the south on the whole.
  • Experimental simulation of dissolution law and porosity evolution of carbonate rock
    SHE Min, SHOU Jianfeng, SHEN Anjiang, PAN Liyin, HU Anping, HU Yuanyuan
    , 2016, 43(4): 564-572. https://doi.org/10.11698/PED.2016.04.08
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    Experiments of acetic acid (initial 0.2%) with porous dolostone, fractured-porous-vuggy dolostone, porous limestone and fractured limestone were done in a continuous flow diagenesis simulation system to find out the controlling factor of dissolution and dissolution effect. The results show that the dissolution quantity of carbonate rock inversely proportional to temperature and directly proportional to pressure, and the temperature effect is greater than the pressure effect. Therefore, relatively shallow burial and lower temperature environment is more beneficial to the formation of large scale carbonate dissolution pores. Quantitative comparison of porosity volume and permeability variation, and evolution of pores inside the rock before and after the experiment show that pore structure has apparent control over the carbonate dissolution and pore evolution. After dissolution, porous dolomite with homogeneous pore distribution saw rise in pore volume (matrix pore volume) and permeability, and remained as pore type in terms of reservoir space; porous limestone, with significant heterogeneity in original pores and texture, saw significant increase in pore volume and permeability, but the increased pores were fracture type, so its reservoir space turned into fracture-pore type; dissolution increased the permeability of fracture-pore dolomite and fracture limestone remarkably by 2-3 orders of magnitude; and the pores increased were mainly along dissolution fractures, turning the reservoir space into fracture-cave type.
  • Constraint of volcano-stratigraphic emplacement environment on the reservoir distribution: A case analysis of rhyolitic volcanic strata in the 2nd member of Jurassic Huoshiling Formation in Wangfu fault depression, Songliao Basin, East China
    TANG Huafeng, YANG Di, SHAO Mingli, WANG Pujun, SUN Wentie, HUANG Yulong
    , 2016, 43(4): 573-579. https://doi.org/10.11698/PED.2016.04.09
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    This paper takes rhyolitic volcanic strata of the 2nd member of Jurassic Huoshiling Formation in the Wangfu fault depression, Songliao Basin as an example to discuss the environment type of volcnano-stratigraphic emplacement and distribution pattern of reservoirs and to analyze the control of volcanic strata emplacement environment on reservoir formation. Lithofacies analysis techniques can roughly determine the paleo-landform before volcnano-stratigraphic emplacement according to the types of underlying rocks. Horizon flatten techniques can basically determine the paleo-landform after emplacement according to coal bottom. There are four environment types of volcano-stratigraphic emplacement, namely, sub-sag before and after emplacement (typeⅠ), sub-sag before emplacement- low salient after emplacement (typeⅡ), low salient before and after emplacement (type Ⅲ), and low salient before emplacement and sub-sag after emplacement (type Ⅳ). The drilling reveals that the volcanic strata of typeⅠemplacement environment have the reservoir distribution pattern of excellent in the lower part and poor in the upper part because of the controlling of capturing of volatile matter, quenching of magma and deep burial dissolution. However, the volcanic strata of type Ⅲ emplacement environment have the reservoir distribution pattern of excellent in the upper part and poor in the lower part because of the controlling of the weathering leaching, capturing of volatile matters and tectonic activity. The lower part of volcanic strata in typeⅠand upper part of volcanic strata in type Ⅲ are favorable exploration targets.
  • Types, characteristics and effects of natural fluid pressure fractures in shale: A case study of the Paleogene strata in Eastern China
    MA Cunfei, DONG Chunmei, LUAN Guoqiang, LIN Chengyan, LIU Xiaocen, ELSWORTH Derek
    , 2016, 43(4): 580-589. https://doi.org/10.11698/PED.2016.04.10
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    Taking the Paleogene organic-rich shales from the Dongying Sag and Zhanhua Sag of Jiyang Depression in Bohai Bay Basin and Northern Jiangsu Basin in Eastern China as examples, this paper researches the types and characteristics of natural fluid pressure fractures and their effects on hydrocarbon primary migration. The study shows that fluid overpressure is the main reason for the formation of natural fluid pressure fractures. The natural fluid pressure fractures include three types, early sluiced fractures, bedding- parallel vein fractures, and hydrocarbon generation and expulsion fractures. Early sluiced fractures have the typical characteristics of snaking morphology, bedding-parallel vein fractures are filled with fibrous calcite vein and coexist with organic matter, and hydrocarbon generation and expulsion fractures generated by hydrocarbon-generating pressurization of kerogen are the key to episodic expulsion of organic-rich shale. Fractures of multiple origins, such as natural fluid pressure fractures, bedding fractures and structural fractures, accumulate gradually, forming interconnected fracture networks which are significant primary migration pathways and reservoir space, act as the seepage channel in the process of multi-scale seepage and are the premise of realizing volume fracturing in shale reservoirs.
  • Features and hierarchical modeling of carbonate fracture-cavity reservoirs
    LI Yang, HOU Jiagen, LI Yongqiang
    , 2016, 43(4): 600-606. https://doi.org/10.11698/PED.2016.04.12
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    Taking the Ordovician fracture-cavity carbonate reservoir of Tahe oilfield,Tarim Basin as an example, the fracture-cavity reservoir has been classified according to the type and size of reservoir space, and a 3-D geological model of fracture-cavity reservoirs was built according to their types and classes. Based on core, drilling, logging and seismic data, the fracture-cavity reservoir was divided into four types, namely cave, vug, fracture and bedrock types, in which the cave type was subdivided into two subtypes, large cave and small cave; and the fracture type was subdivided into four subtypes, large scale fracture, meso-scale fracture, small scale fracture and microfracture. The large cave model was established using deterministic method via seismic truncation and pattern modification. The small cave model was built using the method of multiple-point geostatistical simulation with large cave model as the training image. The vug model was built using sequential Gaussian simulation. The large scale fracture model was established using the deterministic method of manual interpretation, meso-scale fracture model was built using deterministic method of ant tracking, the small scale fracture model was built using stochastic object-based modeling. The micro-fracture and bedrock have no discrete distribution model established because of their poor storage quality. Then the different types of reservoir space models were merged into one model to get the discrete distribution model of typical fracture-cavity unit. The application in Tahe blocks 6 and 7 showed that this hierarchical geological modeling improved the reservoir model precision, guided the water-flooding effectively and advanced the development efficiency.
  • Water and gas distribution and its controlling factors of large scale tight sand gas: A case study of western Sulige gas field, Ordos Basin, NW China
    MENG Dewei, JIA Ailin, JI Guang, HE Dongbo
    , 2016, 43(4): 607-614. https://doi.org/10.11698/PED.2016.04.13
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    The chemical characteristics and occurrence state of formation water in western Sulige gas field were analyzed based on geological features of reservoirs, the gas and water distribution regularity and the main controlling factors were determined. Aquifer zones are widely distributed in the whole Western Sulige gas field, gas zones developed poorly and distributed limitedly. Vertically, gas and water zones are of poor continuity and distributed in an isolated and staggered pattern. Inside the gas reservoir, there is not a uniform gas and water interface because of the hard differentiation between gas and water. On the whole, the lower segment of H8 Member in Shihezi Formation and S1 Member in Shanxi Formation are both better than the upper segment of H8 Member. Gas and water distribution of Western Sulige gas field is mainly controlled by gas-generating intensity, the distances between reservoirs and hydrocarbon source rocks, configuration relationship of sand shale and physical property differences inside sand body complex. Among them, gas-generating intensity mainly controls the macro pattern of gas and water distribution, with the decrease of gas-generating intensity, good gas accumulation gradually changes to be water associated gas reservoir. The closer the distance between reservoirs and hydrocarbon source rocks, the more developed the gas zones, on the contrary, the gas-bearing water zone and coexisting gas and water zone are more developed. Sand shale configuration relationship and physical property differences inside sand body complex mainly control the local gas filling and accumulation. Five types of gas and water distribution patterns are summarized: pure gas, thick reservoir with mixed gas and water, water above the gas, gas above the water, and gas sandwiched between water.
  • Cumulative production curve method for the quantitative evaluation on the effect of oilfield development measures: A case study of the nitrogen injection pilot in Yanling oilfield, Bohai Bay Basin
    DONG Wei, JIAO Jian, XIE Shijian, LYU Cuiyan, CUI Gang, MENG Jie
    , 2016, 43(4): 615-620. https://doi.org/10.11698/PED.2016.04.14
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    To evaluate the effect of oilfield development measures quantitatively, based on the theory of Arps production decline, this study deduced a linear relation between the product of cumulative production with production time (Npt) and production time (t), and established the cumulative production curve method for quantitative evaluation on the effect of development measures. The nitrogen injection pilot in Yanling oilfield was taken as an example to calculate the recoverable reserves before and after the nitrogen injection, and through the variation of recoverable reserves, the effect of the nitrogen injection on actual production was quantitatively evaluated. Similarity analysis of decline curve shape in the late period shows that the method is not restricted by decline types and the relationship curve between Npt and t in the late development is always tending to a straight line. The cumulative production curve method is not only suitable for single wells but also not restricted by reservoir types. Combined with derivative curve in diagnosis, it reflects the microscopic variations of the slope in the straight line segment and the variations of recoverable reserves and the process of reserve producing. The single wells in the Yanbei nitrogen injection pilot were evaluated quantitatively using the cumulative production curve method , the results show that: the nitrogen injection causes obvious productivity increase of the oil wells in the hillside of the buried hill, productivity decrease of the oil wells at the top of buried hill, and little influence on the productivity of oil wells in the margins of burial hill.
  • Multistage interwell chemical tracing for step-by-step profile control of water channeling and flooding of fractured ultra-low permeability reservoirs
    PU Chunsheng, JING Cheng, HE Yanlong, GU Xiaoyu, ZHANG Zhiying, WEI Jikai
    , 2016, 43(4): 621-629. https://doi.org/10.11698/PED.2016.04.15
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    To monitor the dynamic variations of sweep area and formation parameters during the process of multiple slugs step-by-step profile control, the multistage interwell chemical tracing technique was proposed and tested in field, in line with the features of the step-by-step profile control in fractured ultra-low permeability reservoirs and the basic principle of chemical tracing test. According to the design scheme of step-by-step profile control and the characteristics of water channeling and flooding in fractured ultra-low permeability reservoirs, this study worked out times-design method for interwell tracing, optimized the selection principle of chemical tracer and calculation formula of tracer dosage, and set up the parameter optimization forecasting method of step-by-step profile control based on multistage interwell tracing. The application results of the method show multistage interwell chemical tracing can reflect dynamic variation of fractured parameters effectively, and the monitoring results match with the dynamic production testing results, demonstrating good adaptability of the method.
  • Microbial enhanced oil recovery of oil-water transitional zone in thin-shallow extra heavy oil reservoirs: A case study of Chunfeng Oilfield in western margin of Junggar Basin, NW China
    WANG Xuezhong, YANG Yuanliang, XI Weijun
    , 2016, 43(4): 630-635. https://doi.org/10.11698/PED.2016.04.16
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    To improve the production effect of oil-water transitional zone in thin-shallow extra heavy oil reservoirs of Chunfeng Oilfield in western marginal area of the Junggar Basin, microbial enhanced oil recovery was studied taking the P6-P48 well of the oil-water transitional zone as an example. In the early stage of steam stimulation, the P6-P48 well was shut-in due to high water cut caused by edge water incursion, and analysis showed that its reservoir conditions are suitable for microbial cold production technology. According to the P6-P48 well oil sample composition, the study screened indigenous microbe strain of bacillus XJ2-1, aeruginosa XJ3-1, Dietz’s bacteria Z4M8-2, inoculating microbes strain of bacillus SLG5B10-17, nutrient solution, and activator; and designed microbial injection scheme according to near borehole zones treatment radius. In September 2014, 865 m3 of microbial bacterial liquid, nutrient solution and activator was injected and the well was shut in for 166 d of reaction time. The well-hole was opened to produce in March 15, 2015, and has produced 405 d until April 30, 2016, producing oil 3 464 t. The 50 ℃ degassing crude oil viscosity was decreased by 58% after microbial enhanced oil recovery, and the injected live bacteria was found in produced fluid, with more quantity, indicating that the injected bacteria are adaptive and has reproduced in formation condition. Compared with 16 adjacent wells of steam soaking, microbial enhanced oil recovery has long valid period and better economic benefit. Microbial enhanced oil recovery also got good results in the P6-P49 and P6-P47 wells.
  • A nano-particle foam unloading agent applied in unloading liquid of deep gas well
    WU Junwen, LEI Qun, XIONG Chunming, CAO Guangqiang, ZHANG Jianjun, LI Jun, FANG Jin, TAN Jian, AI Tianjing, LI Nan, JIA Min
    , 2016, 43(4): 636-640. https://doi.org/10.11698/PED.2016.04.17
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    To solve the problem of unloading liquid of deep gas well with high gas temperature and salinity, high concentrations of H2S gas and condensate oil, a nanoparticle foam unloading agent was developed and evaluated, and the field test was carried out. The liquid phase foam unloading agent was prepared by blending high temperature resistant anionic surfactant, high salinity and H2S resistant zwitterionic surfactant and the condensate oil resistant fluorocarbon surfactant. The nanoparticle foam unloading agent was developed by introducing silane coupling agent modified nano silica spheres into the liquid phase foam unloading agent as the solid foam stabilizer. The property of nanoparticle foam unloading agent was studied through lab experiment, and the results show that: the agent has temperature resistance as high as 150 ℃, salinity resistance up to 250 g/L, H2S resistance up to 0.04%, condensate oil resistance up to 30%, which proves high foaming ability and foam stabilizing ability. The optical microscope and zeta potential results show that: the mechanism of enhancing the property of liquid phase foam unloading agent by nanoparticles lies in the fact that the nanoparticles can adsorb onto the gas-water interface to form a solid particle film, and it has the best foam stabilizing effect at the modified nano-silica sphere concentration of about 0.002%. The field test results show that: the agent has steady performance, meets the site construction requirements, and can improve the water drainage - gas recovery efficiency in gas well and reduce the cost.
  • Drift-off warning limits for deepwater drilling platform/riser coupling system
    LIU Xiuquan, CHEN Guoming, CHANG Yuanjiang, JI Jingqi, FU Jingjie, SONG Qiang
    , 2016, 43(4): 641-646. https://doi.org/10.11698/PED.2016.04.18
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    The drift-off dynamic model of deepwater drilling platform and riser coupling system was established. An analysis method on drift-off warning limits of deepwater drilling platform and riser coupling system was proposed, and a deepwater drilling platform/riser system was taken for case study. The analysis model of deepwater riser, wellhead and conductor coupling system and the drift-off dynamic model of platform were established respectively. The drift-off dynamic solver of deepwater platform was developed. The coupling dynamic characteristics and coupling effect of the deepwater drilling platform and riser system were analyzed in combination with example, and the analysis method for drift-off warning limits was described. The results show that: the riser load acting on platform plays a driving role in the platform drift-off in the initial drift-off stage, and begins to inhibit the platform drift-off gradually as the drift-off displacement increases; During the platform drift-off, the transient response speed of upper riser parameters is high, while the transient response of lower riser parameters presents an obvious hysteresis effect; As the current speed increases or water depth decreases, the drift-off warning limits of deepwater drilling platform/riser coupling system decrease and the deepwater drilling riser should be disconnected earlier.
  • Wind-induced response of large offshore oil platform
    LIU Hongbing, CHEN Guoming, LYU Tao, LIN Hong, ZHU Benrui, HUANG Ao
    , 2016, 43(4): 647-655. https://doi.org/10.11698/PED.2016.04.19
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    In connection with wind sensitivity for the towering and hollowed-out structures (drilling derrick, crane, etc) of large offshore oil platform, the wind-induced response of towering structure was studied. By the similarity criteria, high frequency force balance tests for the large offshore oil platform under 0-360° wind directions were carried out, and the spatial distribution model of fluctuating wind load acting on platform was presented. Also, the characteristics of wind-induced vibration and the changing rule gust loading factors were obtained precisely through wind-induced assessment in all directions. The results show that: the RMS (Root Mean Square) of the fluctuating across-wind load is about 10% of the fluctuating along-wind load on the platform; the vibration is mainly focused on the towering and hollowed-out structure like derrick, and the RMS of the across-wind acceleration is about 55% of the along-wind acceleration; the towering derrick has a big dynamic magnification of fluctuating across-wind load. The across-wind load can not be neglected in wind resistance design of large offshore oil platform, also the wind-induced response on the top/bottom of derrick and the magnification of fluctuating across-wind load of towering structure should be mainly considered.
  • Controlling bentonite-based drilling mud properties using sepiolite nanoparticles
    AL-MALKI Needaa, POURAFSHARY Peyman, AL-HADRAMI Hamoud, ABDO Jamil
    , 2016, 43(4): 656-661. https://doi.org/10.11698/PED.2016.04.20
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    Sepiolite nanoparticles were added to the bentonite-based drilling mud to control its properties, and the effects of sepiolite nanoparticles on rheological properties and filtration loss of the bentonite-based drilling mud at different temperature and pressure conditions were studied by experiments. For the bentonite-based drilling muds with and without sepiolite nanoparticles, plastic viscosity, yield point, and fluid loss were measured at different temperature and pressure conditions, the core flooding experiments were also conducted at reservoir pressure and temperatures, and fluid loss and formation damage were measured. The results show that: sepiolite nanoparticles can be used to improve the plastic viscosity and yield point of saline and fresh bentonite-based drilling mud; the bentonite-based drilling mud with sepiolite nanoparticles shows a great stability of rheological properties over a wide range of temperature and pressure, especially at high temperatures and pressures; sepiolite nanoparticles reduce the fluid loss and the permeability reduction at reservoir pressure and temperatures. Sepiolite nanoparticles are an ideal additive for bentonite-based drilling mud.
  • Seismic guided drilling technique based on seismic while drilling (SWD): A case study of fracture-cave reservoirs of Halahatang block, Tarim Oilfield, NW China
    SHI Hongxiang, LI Hui, ZHENG Duoming, ZOU Keyuan, GENG Changbo, LIU Wei, LIU Yanmei, ZHEN Lingxia, ZHANG Hui, SHIM Y H
    , 2016, 43(4): 662-668. https://doi.org/10.11698/PED.2016.04.21
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    To deal with the inaccurate three-dimensional positioning of caves in the ultra-deep and high temperature Ordovician carbonate fracture-cave reservoirs in the Halahatang block, this article proposes a new integrated solution which combines seismic guided drilling (SGD) with onshore seismic while drilling (SVWD). SGD technique uses the newly acquired velocity by SVWD to update velocity model and re-place the target position in three-dimensional space to decrease the uncertainty of the target. The primary drilling targets of two wells in the Halahatang block have been selected to verify this solution. It’s the first time to collect onshore SVWD date domestically. The two wells landed in the target successfully by guiding and adjusting wellbore trajectory according to near real-time prediction results obtained from SVWD data. The success of these two wells shows the solution combining SVWD with SGD is practicable in solving the misplacing of target reservoirs caused by velocity and geological model uncertainty.
  • Diagenetic characteristics under abnormally low pressure: A case from the Paleocene of southern Western Sag of Liaohe Depression, Bohai Bay Basin
    MENG Yuanlin, ZHANG Lei, QU Guohui, ZHANG Fenglian, MENG Fanjin, LI Chen, JIAO Jinhe, SHI Lidong
    , 2016, 43(4): 669-674. https://doi.org/10.11698/PED.2016.04.22
    Abstract ( ) Download PDF ( ) Knowledge map Save
    The effect of low pressure and abnormally low pressure on reservoir diagenesis and physical property of the Paleocene in southern part of Western Sag of Liaohe Depression, Bohai Bay Basin have been analyzed using large amounts of pressure, physical property and formation testing data. When formation pressure is low or abnormally low, the pore fluid has lower pressure, the overburden litho-static pressure is largely born by the sandstone framework, sometimes over compaction occurs, leading to densification of reservoir and stronger mechanical compaction; residual formation pressure has a negative correlation with carbonate cement content, low pressure or abnormally low pressure tight sandstone formations have higher carbonate cement content than sandstone formations with hydrostatic pressure or weak overpressure; pore fluid in sandstones with low pressure or abnormally low pressure has higher Si4+, conducive to the siliceous cementation; when dissolution happens, reservoirs with low pressure or abnormally low pressure, poor in original physical properties, are not favorable for the injection of dissolution fluid and the expulsion of dissolution products, so they have weaker dissolution. In summary, reservoirs with low pressure or abnormally low pressure have poorer physical properties.
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