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Characteristics and accumulation model of Oligocene E32 reservoir in Yingxi area,Qaidam Basin
DU Jiangmin, LONG Pengyu, QIN Yingmin, ZHANG Tong, MA Hongyu, SHENG Jun
2021, Vol.33(5): 1–10
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Biostratigraphic characteristics and exploration significance of Wufeng-Longmaxi Formation in northwestern Hunan
ZHANG Bing, TAN G Shuheng, XI Zhaodong, LIN Donglin, YE Yapei
2021, Vol.33(5): 11–21
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281 )
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Palynofacies and sedimentary paleoenvironment of Lower Cretaceous source rocks in Hongliuxia area,Jiuxi Basin
MA Bo, JI Liming, ZHANG Mingzhen, JIN Peihong, YUAN Bochao, LONG Liwen
2021, Vol.33(5): 22–33
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239 )
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Characteristics of high-quality glutenite reservoirs of Urho Formation in Manan area,Junggar Basin
WANG Jian, ZHOU Lu, JIN Jun, XIANG Baoli, HU Wenxuan, YANG Yang, KANG Xun
2021, Vol.33(5): 34–44
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320 )
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291
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Sequence stratigraphy division and evolutionary features of Permian Lucaogou Formation in Jimsar Sag
ZHANG Wenwen, HAN Changcheng, TIAN Jijun, ZHANG Zhiheng, ZHANG Nan, LI Zhengqiang
2021, Vol.33(5): 45–58
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408 )
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Characteristics and genesis of Oxfordian microbial limestone reservoirs in eastern Amu Darya Basin
MA Wenxin, OUYANG Cheng, LIAO Boyong, XU Qiukang, CHEN Renjin, WANG Xin, XIA Huiping, ZHANG Ting
2021, Vol.33(5): 59–69
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Sedimentary characteristics of fluvial dominated shallow water delta front and its control on lithologic reservoir: A case study of Baxigai Formation in south slope of Kuqa Depression
LUO Haoyu, CHEN Jun, ZHANG Xueqi, MENG Xiangxia, ZHAO Fengquan, WU Shaojun, GUO Xuan
2021, Vol.33(5): 70–80
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305 )
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315
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Sedimentary evolution and sedimentary differentiation model of Kepingtage Formation in Shunbei area,Tarim Basin
WANG Suying, ZHANG Xiang, TIAN Jingchun, PENG Minghong, ZHENG Xiaoyu, XIA Yongtao
2021, Vol.33(5): 81–94
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302 )
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317
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Identification and distribution characteristics of coal-bearing source rocks in Pingbei area,Xihu Sag
ZHAO Jing, HUANG Zhilong, LIU Chunfeng, LI Tianjun, JIANG Yiming, TAN Sizhe, HUANG Jun, GUO Xiaobo
2021, Vol.33(5): 95–106
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251 )
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221
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Effective reservoir thickness of main oil layers in Dingbian Oilfield, Ordos Basin
XU Jing, HE Yonghong, MA Fangxia, DU Yanjun, MA Lang, GE Yunjin, WANG Ruisheng, GUO Rui, DUAN Liang
2021, Vol.33(5): 107–119
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344 )
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315
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Pore structure characteristics of tight glutenite reservoirs of Baikouquan Formation in Mahu Sag
DU Meng, XIANG Yong, JIA Ninghong, LYU Weifeng, ZHANG Jing, ZHANG Daiyan
2021, Vol.33(5): 120–131
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456 )
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(13980 KB)
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322
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High precision combined residual static correction method and its application
XU Xingrong, SU Qin, SUN Jiaqing, ZENG Huahui, XIAO Mingtu, LIU Mengli
2021, Vol.33(5): 132–139
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282 )
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291
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Oil-bearing evaluation method based on NMR free relaxation characteristics: A case study of conglomerate reservoirs of lower Urho Formation in Mahu Sag,Junggar Basin
MAO Rui, MU Liwei, WANG Gang, FAN Haitao
2021, Vol.33(5): 140–147
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Simulation of oil-water two-phase flow based on shale pore network model
WANG Jingyi, ZHOU Zhijun, WEI Huabin, CUI Chunxue
2021, Vol.33(5): 148–154
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Application of APR plugging agent with temperature and salt resistance in Yingmaili gas reservoir
YI Jun, TU Zhixiong, PENG Jianyun, KONG Chang'e, WEI Junhui, LI Jianming
2021, Vol.33(5): 155–162
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Water displacement rules of sandstone reservoirs at extra-high water-cut stage
LI Chuanliang, WANG Fenglan, DU Qinglong, YOU Chunmei, SHAN Gaojun, LI Binhui, ZHU Suyang
2021, Vol.33(5): 163–171
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Flow regulation adaptability of rubber particles in longitudinal double-layer fractured-vuggy reservoirs
MAO Zhiqiang, ZHANG Wen, WU Chunzhou, CHEN Lifeng, CHEN Yadong, LI Gang, ZENG Huiyong, LIU Liang
2021, Vol.33(5): 172–180
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A fully coupled fluid flow and geomechanics model for enhanced coalbed methane recovery
WEI Zhijie, KANG Xiaodong
2021, Vol.33(5): 181–188
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Characteristics and accumulation model of Oligocene E32 reservoir in Yingxi area,Qaidam Basin
DU Jiangmin, LONG Pengyu, QIN Yingmin, ZHANG Tong, MA Hongyu, SHENG Jun
2021, Vol.33(5): 1–10
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doi: https://doi.org/10.12108/yxyqc.20210501
In recent years, a large oil and gas field with a reserve of 100 million tons has been found in Yingxi area of Qaidam Basin. In order to study the reservoir characteristics and accumulation model of E32 of Oligocene in Yingxi area, core observation and thin section identification, X-ray diffraction analysis, physical property test, scanning electron microscope analysis, structural evolution study and reservoir forming condition analysis were carried out. The results show that:(1) The Oligocene E32 reservoir in Yingxi area is large in scale, mainly composed of lacustrine carbonate rocks, with terrigenous clastic, argillaceous and various salt minerals.(2) The physical properties of the rock are mainly of low porosity and ultra-low permeability, and the pore types include dolomite intercrystalline pores, dissolved pores and various micro fractures.(3) The Yingxiongling area is characterized by north-south zonation and east-west segmentation, and its evolution has experienced three stages:Paleocene-Miocene fault depression(29.3-23.8 Ma), early Pliocene weak compression(23.8-7.2 Ma) and strong compression in late Pliocene-Quaternary(7.2 Ma-present).(4) The E32 reservoirs in Yingxi area have the characteristics of self-source and self-reservoir. TOC and Ro of the source rocks are mostly 0.5%-1.0% and 0.6%-0.9% respectively, with low abundance, medium quality and low maturity, but the rocks contain a lot of soluble organic matter. Highquality caprock is developed in the upper salt interlayer group, structural fractures and interlayer fractures are oil and gas migration channels, abnormal high pressure is the main driving force of oil and gas migration, and there are "overpressure+buoyancy" driving and "overpressure+diffusion" driving types. Multi-stage, continuous charging and late accumulation have laid the foundation for the formation of large oil and gas reservoirs with a billion tons. The results of this study have a guiding role for oil and gas exploration of Oligocene in Yingxi area.
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Biostratigraphic characteristics and exploration significance of Wufeng-Longmaxi Formation in northwestern Hunan
ZHANG Bing, TAN G Shuheng, XI Zhaodong, LIN Donglin, YE Yapei
2021, Vol.33(5): 11–21
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doi: https://doi.org/10.12108/yxyqc.20210502
The black shale is widely developed in Wufeng Formation of Upper Ordovician and Longmaxi Formation of Lower Llandovery in northwestern Hunan, which has good prospects for shale gas exploration and development. In order to study its biostratigraphic characteristics, the fossil species of well XY-3 were analyzed. Combined with graptolite and natural gamma(GR) logging curves, the sequence of biological graptolite in the study area was established. According to the changes of organic matter abundance, mineral composition and sedimentary environment of each graptolite zone, the favorable enrichment intervals of shale gas in the study area were identified. The results show that:(1) Wufeng-Longmaxi Formation in the study area can be divided into eight graptolite zones:WF2, WF3, WF4, LM2-LM3, LM4, LM5, LM6, LM7. Affected by the uplift of underwater highland in Hunan and Hubei, the study area lacks LM1 zone.(2) WF2-WF3 and LM2-LM4 graptolite zones were deposited in poor oxidation environment, and the lithology was medium carbon siliceous shale facies. WF4 graptolite zone was deposited in oxidation environment, and its lithology was low-carbon mixed shale facies. LM5-LM7 graptolite zone was deposited in oxidation environment, and its lithology was low-carbon clay shale facies. WF2-WF3 and LM2-LM4 graptolite zones were characterized by high TOC, high brittleness and high porosity, and have certain hydrocarbon generation potential and fracturing ability, which can be used as favorable intervals for shale gas exploration(. 3) Compared with Changning and other areas, the thickness of organic matter rich layers in the study area was relatively thin, and the abundance of organic matter was relatively low. Because it was affected by the underwater highlands in Hunan and Hubei, the relatively oxidized water body was not conducive to the preservation of organic matter, and some organic matter rich layers were missing. The research results can provide reference for shale gas exploration in northwestern Hunan.
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Palynofacies and sedimentary paleoenvironment of Lower Cretaceous source rocks in Hongliuxia area,Jiuxi Basin
MA Bo, JI Liming, ZHANG Mingzhen, JIN Peihong, YUAN Bochao, LONG Liwen
2021, Vol.33(5): 22–33
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doi: https://doi.org/10.12108/yxyqc.20210503
It is lacking on understanding of the hydrocarbon generation potential of the Lower Cretaceous source rocks in Jiuxi Basin, and it is also controversial on understanding of their sedimentary paleoenvironment. Based on the systematic analysis of palynofacies and element geochemistry of Xiagou Formation in Hongliuxia area, the source of organic matter, hydrocarbon generation potential and sedimentary paleoenvironment characteristics of source rocks were studied. The results show that three types of palynofacies, A(phytoclasts-amorphous assemblages), B(amorphous assemblages) and C(phytoclasts assemblages), are developed in Xiagou Formation in Hongliuxia area, and the palynofacies C is dominant. Phytoclasts from terrestrial higher plants dominate the palynological organic matter and the organic matter is mainly type Ⅲ, which shows poor oil-generating potential. The amorphous organic matter contents in some intervals of the lower and upper members are relatively high and the organic matter is type Ⅱ2, with some oil-generating potential. The element geochemical parameters indicate a semihumid-humid climate with a tendency of gradually humid in the late stage, and a mainly brackish-saline and oxic water environment with low productivity during the deposition of Xiagou Formation, and only some intervals in the lower and upper members were deposited in a suboxic-anoxic deep-water environment. The Xiagou Formation in Hongliuxia area is mainly composed of proximal alluvial fan-delta and shore shallow lake subfacies. In the early and late sedimentary period, the water body is stable, and some good source rocks were developed, otherwise, in the middle sedimentary period, proximal oxidation delta shore shallow lake subfacies and poor source rocks were developed.
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Characteristics of high-quality glutenite reservoirs of Urho Formation in Manan area,Junggar Basin
WANG Jian, ZHOU Lu, JIN Jun, XIANG Baoli, HU Wenxuan, YANG Yang, KANG Xun
2021, Vol.33(5): 34–44
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doi: https://doi.org/10.12108/yxyqc.20210504
The glutenite reservoirs of Urho Formation in Manan area of Junggar Basin has large-scale exploration potential and is a favorable field for increasing reserves and production. The sedimentary microfacies, reservoir space types and reservoir properties of Urho Formation were systematically analyzed by means of rock and mineral identification, SEM, XRD and porosity and permeability analysis. The results show that Urho Formation was deposited in shallow water fan delta and seven sedimentary microfacies were developed, of which underwater channel sandy fine conglomerate and sandstone are the dominant sedimentary facies belt for reservoir development due to their good physical properties. During diagenesis, compaction and laumontite cementation significantly damaged primary intergranular pores, whereas the dissolution of laumontite cement and feldspar debris produced a large number of secondary pores. As a result, secondary pores became the dominant reservoir space, followed by residual intergranular pores and microfractures. Overall, the occurrence of high-quality reservoirs is mainly influenced by sedimentary microfacies, zeolite types and their content, and the activity intensity of acid geofluids charging these strata. The high-quality reservoirs were formed in a genesis model of sedimentary controlling-fault connectingacid fluid transforming. In the favorable microfacies such as subaqueous channel, when it had related to underlying source rocks by faults, the activity of acid hydrocarbon-bearing fluids was strong. The fluids promoted the dissolution of laumontite. The superimposed layers of subaqueous channels near the faults are high-quality reservoir of Urho Formation.
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Sequence stratigraphy division and evolutionary features of Permian Lucaogou Formation in Jimsar Sag
ZHANG Wenwen, HAN Changcheng, TIAN Jijun, ZHANG Zhiheng, ZHANG Nan, LI Zhengqiang
2021, Vol.33(5): 45–58
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doi: https://doi.org/10.12108/yxyqc.20210505
To clarify the sequence stratigraphic characteristics and evolution of the Permian Lucaogou Formation in Jimsar Sag, many drillings core analysis, well logging analysis and seismic data interpretation were carried out. The distribution characteristics of the sedimentary microfacies of the Lucaogou Formation were comprehensively studied. The results show that:(1) The Lucaogou Formation of the Jimsar Sag, from bottom to top, can be divided into two third-order sequences(SQ1 and SQ2), and SQ1 can be divided into lowstand(LST), transgressive (TST) and highstand system tracts(HST), SQ2 can be divided into TST, HST. "sweet spots" is formed in HST. (2) The Lucaogou Formation is a set of delta-salined lake sedimentary system, which can be identified 8 sedimentary microfacies(sand dam, pre-delta mud, beach sand, shallow lake mud, mixed flat, dolomitic flat, semideep lake mud and turbidite deposit).(3) During the depositional period of the Lucaogou Formation in Jimsar Sag, mixed deposition of terrigenous clastics and carbonate rocks continued to exist. The terrigenous clastic delta sedimentary system was more developed in the early stage, and the saline lake sedimentary system was more developed in the late stage.(4) Climate, intensity of material supply and periodic rise and fall of the lake level control the stratigraphic development and sedimentary evolution of Lucaogou Formation in Jimsar Sag. The research results have guiding significance for the petroleum exploration of Permian Lucaogou Formation in Jimsar Sag.
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Characteristics and genesis of Oxfordian microbial limestone reservoirs in eastern Amu Darya Basin
MA Wenxin, OUYANG Cheng, LIAO Boyong, XU Qiukang, CHEN Renjin, WANG Xin, XIA Huiping, ZHANG Ting
2021, Vol.33(5): 59–69
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doi: https://doi.org/10.12108/yxyqc.20210506
The Upper Jurassic Oxfordian microbial limestone layer is the most important oil & gas exploration target layer in eastern Amu Darya Basin. Clarifying the characteristics and genesis of this microbial reservoir has important theoretical and practical significance for oil & gas exploration and development. Based on cores, thin sections, physical properties and geochemical analysis data of 36 wells, combined with logging and seismic data, the sedimentary microfacies characteristics, reservoir petrology and physical properties, reservoir space characteristics and reservoir types were studied, and the genesis of microbial limestone reservoir was discussed. The results show that the depositional environment of Karabek Sag-Sandy Klei uplift-Beishkent depression is undulating up gentle slope, and microfacies of microbial adhesion mound, reef, shoal, mound shoal or reef shoal are widely developed. Thrombolite is the best reservoir rocks with type Ⅱ. Pellets, sand, biological limestone, which are formed by microbial aggregation or bonded, is the secondly developed reservoir rocks with type Ⅲ. The depositional environment of Kisar piedmont front is bottom gentle slope, mainly developed microfacies containing microbial particles muddy limestone, and reservoir rocks are microbial granular micrite limestone and micritic limestone with type Ⅳ reservoir, which formed by tectonic movement and dissolution transformation. It is concluded that favorable microbial adhesion mounds, reefs, shoals have been in a shallow buried diagenetic environment with a long time, which is conducive to preservation of primary intragranular pores. It is an important foundation for the development and formation of Oxfordian microbial rock reservoirs in the study area. The faults and microcracks, formed in two stages of tectonic movement(Late Yanshan 119 Ma, Early Himalayan 61.31 Ma), are beneficial for the reservoir reformation of microbial mound, reefs, shoal microfacies. It is another important condition for the development and formation of microbial limestone reservoirs in the study area. Three types of fluid superimposed dissolution and reformation on the reservoir, including hydrocarbon rapidly invading and dissolution by organic acid, high temperature formation fluid and deep hydrothermal fluid, TSR reaction, are the key for the development and formation of microbial reservoirs in the study area.
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Sedimentary characteristics of fluvial dominated shallow water delta front and its control on lithologic reservoir: A case study of Baxigai Formation in south slope of Kuqa Depression
LUO Haoyu, CHEN Jun, ZHANG Xueqi, MENG Xiangxia, ZHAO Fengquan, WU Shaojun, GUO Xuan
2021, Vol.33(5): 70–80
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doi: https://doi.org/10.12108/yxyqc.20210507
Two lithologic reservoirs have been discovered in south slope of Kuqa Depression, which shows the great potential of Cretaceous lithologic reservoirs exploration in this area. To further expand the field of lithologic reservoir exploration in Cretaceous Baxigai Formation, based on core observation, well logging facies, seismic facies, ratio of the sand and formation and paleogeomorphology, it is confirmed that the provenance of member U, M and L are from south Halahatang and south Yingmaili. The sedimentary system is fluvial dominated shallow water delta. The member M and L of Baxigai Formation are distributed in the southeast Halahatang, and inner front shallow lacstrine subfacies of fluvial dominated shallow water delta are developed. The member U are distributed in the project, which is a retrograde depositional model, inner front-outer front-shallow lacstrine facies of fluvial dominated shallow water delta are developed. The structure of the project is dip northward, and the provenance comes from the south. The sheet sand at the top of the inner front, the underwater distributary channel on the flank of the outer front and the sheet sand at the tip of the outer front are the favorable facies for lithologic reservoir exploration. The south Yingmaili and well annulus of yd7-ym46-dh26 are prospects for Cretaceous lithologic reservoirs exploration in member U of Baxigai Formation. The results can provide a basis for further exploration of Cretaceous lithologic reservoirs in south slope of Kuqa Depression.
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Sedimentary evolution and sedimentary differentiation model of Kepingtage Formation in Shunbei area,Tarim Basin
WANG Suying, ZHANG Xiang, TIAN Jingchun, PENG Minghong, ZHENG Xiaoyu, XIA Yongtao
2021, Vol.33(5): 81–94
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doi: https://doi.org/10.12108/yxyqc.20210508
In order to study the significant differences of sedimentary patterns in different stages in tidal flat-shelf sedimentary system of Kepingtage Formation in Shunbei area of Tarim Basin, by using common section identification, core observation and description, the data of seismic, well logging and single well, a comprehensive analysis was carried out on the basis of the division and comparison of lithologic sections. The results show that:(1) The Kepingtage Formation in Shunbei area is controlled by palaeo-uplift, and there are two types of stratigraphic structures: "three-section" (lower sandstone interval, mudstone interval and sandstone interval are all developed) and "one-section" (lack of lower sandstone interval, mudstone interval or middle and lower part of mudstone interval).(2) Tidal flat-shelf depositional system controlled by palaeo-uplift in the background of transgression is developed in Kepingtage Formation in Shunbei area. The depositional pattern is significantly different in the early and late depositional periods. In the early stage, it was controlled by palaeo-uplift, and the sedimentary facies zones were differentiated in the east-west direction and distributed in a ring along the palaeo-uplift. In the late stage, the paleo-uplift was submerged and no longer controlled the distribution of sedimentary facies zones. Due to the influence of basin boundary, the sedimentary pattern evolved from east-west differentiation to north-south differentiation. The sedimentary facies zones extended from east-west to north-south as a whole, and distributed symmetrically along the continental shelf sedimentary area.(3) Kepingtage Formation has experienced the water by the "shallow-deep, shallow and deep-shallow" evolution of sea-level change, several sets of reservoir-cap assemblages are developed vertically, and subtidal sand flat and tidal-subtidal tidal channel are favorable reservoir sand bodies. The research results can provide favorable target area and exploration direction for oil and gas exploration of marine clastic rocks.
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Identification and distribution characteristics of coal-bearing source rocks in Pingbei area,Xihu Sag
ZHAO Jing, HUANG Zhilong, LIU Chunfeng, LI Tianjun, JIANG Yiming, TAN Sizhe, HUANG Jun, GUO Xiaobo
2021, Vol.33(5): 95–106
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doi: https://doi.org/10.12108/yxyqc.20210509
The coal-bearing source rocks of Pinghu Formation in Pingbei area, Xihu Sag, have three kinds of lithology:coal, carbonaceous mudstone and mudstone. In order to clarify the development and distribution characteristics of various coal-bearing source rocks, and determine the key factors for the development of high-quality source rocks, through the analysis of geochemical characteristics and the evaluation of effective source rocks of coal-bearing source rocks in Pingbei area, the lithologic logging identification model was established. Combined with the prediction results of lithology distribution and TOC content of mudstone, the development characteristics and distribution law of coal-bearing source rocks in study area were clarified. The results show that:the coal and carbonaceous mudstone of Pinghu Formation are high quality source rocks, and the mudstone with w(TOC) >1.0% are effective source rocks. Organic matter types of coal-bearing source rocks are mainly Ⅱ-Ⅲ types, generally reaching low maturity to maturity stage. The distribution of coal-bearing source rocks is obviously controlled by Paleo water depth. Transgression occurred in the middle part of sedimentary period of Pinghu Formation, is conducive to the development of coal-bearing source rocks. The sedimentary centers of coal are mostly distributed in the depression between uplifts;besides, the carbonaceous mudstone and coal have symbiotic relationship. The effective mudstone thickens with the increase of water depth. The Paleotopography and the active rate of growth faults in Pingbei area affect the local water bodies, which are the key factors for the development of high-quality coal-bearing source rocks. The research results have guiding significance for hydrocarbon generation potential evaluation and favorable area prediction in Pingbei area, Xihu Sag.
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Effective reservoir thickness of main oil layers in Dingbian Oilfield, Ordos Basin
XU Jing, HE Yonghong, MA Fangxia, DU Yanjun, MA Lang, GE Yunjin, WANG Ruisheng, GUO Rui, DUAN Liang
2021, Vol.33(5): 107–119
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doi: https://doi.org/10.12108/yxyqc.20210510
The Mesozoic reservoirs in Shajian area of Dingbian Oilfield, Ordos Basin are characterized by strong reservoir heterogeneity, overlapping of multiple oil-water systems and coexistence of low resistivity and conventional resistivity reservoirs. In order to identify effective reservoirs, based on core, logging, formation test and production test, high-pressure physical properties and sealed coring data, the logging interpretation models of Yan 9, Chang 6 and Chang 9 reservoirs were established. Then, lower limits of effective thickness of each reservoir were comprehensively analyzed, and the origin of the difference of lower limits of physical and electrical properties were discussed. The results show that:①The lower limits of effective thickness porosity of Main oil reservoirs in Shajian area of Dingbian Oilfield are 12.5%, 9.0%, 7.0% respectively, the lower limits of permeability are 2.0 mD, 0.2 mD, 0.3 mD respectively, the lower limits of acoustic time difference are 239 μs/m, 222 μs/m, 213 μs/m respectively, the lower limits of resistivity are 6.0 Ω·m, 13.0 Ω·m, 17.5 Ω·m respectively, and the lower limits of oil saturation are 47.5%, 44.0%, 41.5% respectively.② Differential diagenesis results in the difference of the lower limits of physical property of each reservoir. The physical property conditions of Yan 9 reservoir with weak compaction and carbonate cementation are better than those of Chang 6 and Chang 9;The development of chlorite film in Chang 6 reservoir preserves some intergranular pores, while authigenic clay mineral is easy to block the pore throats, resulting in low permeability. The porosity of Chang 9 oil reservoir reduced by strong compaction and cementation is larger than that of Chang 6 oil reservoir, but the improvement of permeability by dissolution is stronger than that of Chang 6 oil-bearing formation. ③The intrusion of drilling fluid, the influence of reservoir physical properties and additional conductivity of clay are the main reasons for the lower limits of resistivity of Yan 9 oil reservoir. Understanding the difference and the origin of the lower limits of effective thickness for the main oil-bearing formations will help to understand the variation of Mesozoic reservoirs in Ordos Basin and improve the prediction accuracy of favorable reservoir areas.
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Pore structure characteristics of tight glutenite reservoirs of Baikouquan Formation in Mahu Sag
DU Meng, XIANG Yong, JIA Ninghong, LYU Weifeng, ZHANG Jing, ZHANG Daiyan
2021, Vol.33(5): 120–131
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doi: https://doi.org/10.12108/yxyqc.20210511
The Baikouquan Formation in Mahu Sag is an important oil and gas accumulation area of glutenite. In order to study the pore structure characteristics of tight glutenite reservoir of Baikouquan Formation in Mahu Sag. The analyses of mercury injection, nuclear magnetic resonance and cast thin sections were carried out. Combined with micro-CT scanning technology, quantitative evaluation of minerals by scanning electron microscope(QEMSCAN) and MAPS micro-image splicing technologies, the comprehensive study of microscopic pore structure characteristics from scale and precision, two-dimension and three-dimension were carried out. The results show that:(1) The pore throat scales of tight glutenite reservoirs of Baikouquan Formation in Mahu Sag are widely distributed, showing obvious bimodal characteristics. The large-scale pore throats are submicron to micron scale, while small scale pore throats are nano to submicron scale. The contribution rate of 0.5-4.0 μm throat is the highest, and the contribution rate of micron scale pore throat to seepage is greater.(2) On micron scale, the pore structure has the characteristics of strong heterogeneity and complex mode. The main pore types are dissolution pore, intergranular pore and micro fracture. The distribution states of pores are mainly banded and isolated. The contribution of pore connectivity to seepage is greater than pore scale.(3) On nano scale, scanning electron microscope show that the main mineral components are quartz and feldspar. The compaction between grains is sufficient, and the grain shape is closely combined. The morphology of nano pores in the samples matrix with different porosity and permeability are distinctive, mainly the honeycomb feldspar dissolution pores in mineral grains (crystals) or micropores on the surface of interstitial materials, and the cleavage fracture of calcite particles can be observed, which play a good role in communicating the micro spherical pores and nano dissolved pores. The research results can provide reference for the pore structure characterization and "sweet spot" prediction of tight glutenite reservoirs.
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High precision combined residual static correction method and its application
XU Xingrong, SU Qin, SUN Jiaqing, ZENG Huahui, XIAO Mingtu, LIU Mengli
2021, Vol.33(5): 132–139
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doi: https://doi.org/10.12108/yxyqc.20210512
The residual static correction method is usually used to eliminate the influence of medium and short wavelength on imaging after solving the basic static correction, but a single residual static correction method cannot completely solve the problem. Based on surface-consistent residual static correction theory, the residual static correction method of space variant multi-time window fusion was used to build space variant model trace. The multi-scale frequency division residual static correction method was used to eliminate the effect of frequency on model trace, and a time-varying residual static correction method based on common imaging point(CIP) gathers was adopted in imaging gathers. The high precision combined residual static correction scheme integrated of the three residual static correction methods was tested in complex structural area with wide azimuth, wide frequency and high density. The results show that the scheme not only considers the calculation efficiency, but also improves the calculation accuracy. The scheme can effectively solve the problem of residual static correction in low SNR and complex structure area with "two widths and one height".
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Oil-bearing evaluation method based on NMR free relaxation characteristics: A case study of conglomerate reservoirs of lower Urho Formation in Mahu Sag,Junggar Basin
MAO Rui, MU Liwei, WANG Gang, FAN Haitao
2021, Vol.33(5): 140–147
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doi: https://doi.org/10.12108/yxyqc.20210513
The conglomerate reservoirs of Lower Urho Formation in Mahu Sag of Junggar Basin have the characteri-stics of low porosity, low permeability, complex pore structure and strong heterogeneity. Conventional electrical logging and nuclear magnetic resonance(NMR) difference spectrum method are difficult to reflect the oilbearing characteristics of the reservoirs. To clarify the oil-bearing characteristics, NMR free relaxation measurements of light crude oil and NMR experiments of reservoir cores containing different fluids of lower Urho Formation were carried out. The results show that:①The transverse relaxation time of NMR free relaxation T2 spectrum of light crude oil starts from 100.00 ms. ②The T2 spectrum of saturated water core converges to 100.00 ms. ③The NMR T2 spectrum of saturated oil core shows free relaxation characteristics similar to that of crude oil after 100.00 ms. The above phenomenon shows that the core of study area is mainly wetted by water, and the signal of NMR T2 spectrum of saturated oil core greater than 100.00 ms is caused by the free relaxation of light oil. Taking 100.00 ms as the oil-bearing signal of NMR logging, the sensitive parameters were constructed, and the identification chart of fluid properties based on NMR free relaxation features was established. Considering the influence of permeability on oil-bearing property, a calculation model of oil saturation was established. The above method was used to evaluate the oil-bearing property of 31 layers in 22 exploration wells in the study area, the coincidence rate of logging interpretation approached to 93.5%, indicating that the method was effective. This method provides a new idea for the application of NMR logging in oil-bearing evaluation.
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Simulation of oil-water two-phase flow based on shale pore network model
WANG Jingyi, ZHOU Zhijun, WEI Huabin, CUI Chunxue
2021, Vol.33(5): 148–154
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doi: https://doi.org/10.12108/yxyqc.20210514
In order to understand the flow characteristics of shale oil and the formation mechanism of microscopic remaining oil, the shale reservoir of the Shahejie Formation in Jiyang Depression was taken intuitively and accurately as the research object, and the focused ion beam scanning electron microscope system was used for scanning imaging. A three-dimensional digital core was constructed and a pore network model was extracted. The pore structure parameters were analyzed, and then the physical properties of the three-dimensional pore network model were compared with the laboratory experimental physical data to verify the accuracy of the model. On the basis of the pore network model, the pore throat structure characteristics of the samples were analyzed, and a mathematical model of oil-water two-phase seepage flow was established in combination with the Navier-Stokes equation. The finite element method was used to solve model, and the oil-water two-phase microscopic flow simulation was carried out. The results show that the shale samples have the characteristics of complex pore structure, low pore coordination number and poor connectivity. The reservoir space and flow space of shale oil are mainly nano-scale pores. The fluid flow in the pore network model is complex, and the recovery degree increases with the increase of displacement pressure. The higher the pressure is, the easier the fingering phenomenon occurs, and the local remaining oil will be formed. The size of local narrow throat is the key factor to limit the flow of fluid. When the wettability of the wall is water wet, the displacement effect is the best, while the model is oil wet, the displacement effect is the worst, and the remaining oil is not easy to form when the neutral wetting is in. The results of this study are of great significance for the study of oil-water two-phase flow of shale oil under micro conditions. The size of the locally narrowed throat is a key factor restricting fluid flow. When the wall wettability is water-wet, the oil displacement effect is the best, while the model wall is oil-wet, the oil displacement effect is the worst, and the remaining oil is not easy to form When the wall is neutrally wet. The research results have guiding significance for the study of oil-water two-phase flow of shale oil under microscopic conditions.
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Application of APR plugging agent with temperature and salt resistance in Yingmaili gas reservoir
YI Jun, TU Zhixiong, PENG Jianyun, KONG Chang'e, WEI Junhui, LI Jianming
2021, Vol.33(5): 155–162
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doi: https://doi.org/10.12108/yxyqc.20210515
In view of the current situation of serious water production in Yingmaili gas reservoir of Tarim Oilfield, an integrated technology of water control and gas drainage was innovatively proposed. The APR plugging agent system suitable for gas reservoirs with high temperature, high pressure and high salinity was developed through laboratory experiments, which was composed of 1% acrylamide/acryloyl morpholine/vinylpyrrolidone terpolymer(APR) + 0.6% polyethyleneimine+ 0.6% modified alumina nanoparticles+ 0.2% thiourea. The temperature and salt resistance and long-term stability of the gel system were investigated, and the plugging ability of the plugging agent was evaluated through physical model experiments. The results show that APR plugging agent has good temperature resistance and long-term thermal stability. Under the condition of formation water(salinity is 23.33×104 mg/L) at 107-150℃, the gelation time can be adjusted and controlled within 2-14 h, gel strength is maintained at grade G, and the maximum dehydration rate is only 7.1% after 180 d, with good plugging performance. In the integrated way of water control and gas drainage, 0.5 PV gelling liquid was injected first, and then 6 PV of N2 was injected. After solidifying and crosslinking of the gelling liquid, the gel has the best ability of water plugging and gas drainage, and the plugging capacity of the gel to water is 9 times that to gas. This APR plugging agent system provides technical support for efficient development of gas reservoirs with high temperature, high pressure and high salinity, so it has broad application prospects.
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Water displacement rules of sandstone reservoirs at extra-high water-cut stage
LI Chuanliang, WANG Fenglan, DU Qinglong, YOU Chunmei, SHAN Gaojun, LI Binhui, ZHU Suyang
2021, Vol.33(5): 163–171
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doi: https://doi.org/10.12108/yxyqc.20210516
Water-flooded sandstone reservoirs showed quite different production characteristics and water displacement rules at the extra-high water-cut stage from the high water-cut stage. The theoretical models of reservoirs at high water-cut stage cannot be applied to the production practice of reservoirs at the extra-high water-cut stage. In order to manage the reservoir production at the extra-high water-cut stage properly, a study was carried out based on the production data of reservoir DT to find out the water displacement rules and displacement mechanism. There are some conclusions as following. The reservoirs at extra-high water-cut stage showed the main aspects of "one high and two lows", i.e. high water-cut, low production rate and low recovery factor. The decline ratio of production rate and the rising rate of water-cut are also quite low. There is tremendous remaining oil underground being worth recovering. Reservoir oil is displaced through two basic mechanisms, one is water-driving recovery and the other is water-flooding recovery. The continuous oil is produced by water-driving recovery with high efficiency, and the discrete oil is produced by water-flooding recovery with low efficiency. At the early stage of development, reservoirs are produced mainly through water-driving recovery, while in the late stage mainly through water-flooding recovery which is converted from the water-driving recovery in the early stage. The water drive curve and the water-oil ratio curve are approximate straight lines at high water-cut stage. However, the lines are up warding at extra-high water-cut stage from high water-cut stage, which means that the recovery mechanism is converting from the water-driving to the water-flooding with the recovery efficiency changing worse. The efficiency of oil recovery predicted by the displacement rules of high water-cut stage is higher than that predicted by the displacement rules of extra-high water-cut stage, for example it is 5.24 percent points for reservoir DT. The recovery efficiency enhancement of reservoirs is always realized through the enhancement of recovery factor, which includes three measures of expanding water-sweep, deepening water-flooding and increasing displacement efficiency. Long term water flooding can also enhance the reservoir recovery factor. Reservoir development at extra-high water-cut stage should be focused on the increasing of sweep factor, meanwhile the displacement efficiency of oil will be increased simultaneously during development of reservoirs.
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Flow regulation adaptability of rubber particles in longitudinal double-layer fractured-vuggy reservoirs
MAO Zhiqiang, ZHANG Wen, WU Chunzhou, CHEN Lifeng, CHEN Yadong, LI Gang, ZENG Huiyong, LIU Liang
2021, Vol.33(5): 172–180
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doi: https://doi.org/10.12108/yxyqc.20210517
In order to solve the problems of oil well flooding and production decline caused by strong heterogeneity, a new type of rubber particle flow regulating agent was used to study the water flooding rule and injection parameter optimization of longitudinal double-layer fractured-vuggy reservoirs through micro-displacement experiment of plexiglass etching model. The results show that the resistance of solid media to fluid flow is almost zero when the oil-water two-phase flow occurs, and the gravity action is prominent. Therefore, there are still a lot of residual oil of karst cave, flow around oil and attic oil with poor connectivity after the longitudinal doublelayer fractured-vuggy reservoir is displaced by injected water. In addition, the injection parameters of rubber particle flow regulating agent were optimized. The optimal injection volume is 0.02 PV, the optimal particle size is 0-1 mm and 2-4 mm, and the optimal injection speed is 25 mL/min. The research results were applied to well TK50 X, and good effect of increasing oil production and decreasing water cut has been achieved. The research results can provide some reference for the future research of longitudinal double-layer fractured-vuggy reservoirs.
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A fully coupled fluid flow and geomechanics model for enhanced coalbed methane recovery
WEI Zhijie, KANG Xiaodong
2021, Vol.33(5): 181–188
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doi: https://doi.org/10.12108/yxyqc.20210518
In order to capture the complicated geomechanical effects more accurately during enhanced coalbed methane recovery, a fully coupled fluid flow and geomechanics model was proposed for ECBM and CO2 underground storage with consideration of multi-component, multi-phase, multi-process transportation in porous media, which consist of poroelastic geomechanical model and full component fluid-flow model. The corresponding numerical solver was developed by the fully implicit finite difference method. The fully coupled model and algorithm was applied to make a systematic comparison and analysis with the commonly used commercial ECBM/CBM software, and to historical match field data of an enhanced CBM recovery pilot by flue gas injection in FBV 4 A. The results show that the model proposed can more accurately capture the fully coupling effects of geomechanics and fluid flow and multi-component multi-process migration in coal seam, which can provide better prediction of reservoir properties and CBM production, indicating its value in field application.