Lithologic Reservoirs

In order to study the characteristics and controlling factors of lacustrine fine-grained sediments of the fourth member of Shahejie Formation in Dongying Depression,core description,thin section identification and X-ray diffraction whole-rock analysis were carried out. The results show that:(1)The fine-grained sedimentary rocks in the study area can be divided into 15 types of lithofacies,among which five types of litho-facies are relatively developed,including organic-rich flat ruled lime clay rock,organic-rich blocky clay rock,organic-rich blocky lime-containing clay rock,organic-lean corrugated clay limestone,organic-lean corrugated clay-containing limestone.(2)According to the changes of pyrite content, Ca(/Ca+ Fe), Zr/Al, and Sr/Ca ratios in the vertical direction,the sedimentary evolution of the upper submember of the fourth member of Shahejie Formation in Dongying Depression can be divided into four stages:drought stage,drought-warm wet transition stage,warm and wet stage and warm wet-drought transition stage.(3)Palaeoclimate conditions controlled the types and characteristics of rocks. In the drought stage,organic-lean corrugated clay limestone was developed. In the drought-warm wet transition stage,organic-rich flat ruled lime clay rock was developed. In the warm stage,organic-rich blocky clay rock was developed. In the warm wet-drought transition stage,organic-rich blocky clay rock and lime clay rock were developed. The results of this study can be used as a reference for oil and gas exploration of finegrained sedimentary rocks.

Geochemical characteristics and exploration significance of shale of Lujiaping Formation in northern Dabashan area

ZHONG Hongli, WU Yufeng, SHAN Chenchen

2020, Vol.32(5): 13–22 Abstract ( 278 ) PDF (5553 KB) ( 375 )

doi: https://doi.org/10.12108/yxyqc.20200502

In order to reveal the hydrocarbon generating potential of the dark shale of Lower Cambrian Lujiaping Formation in northern Dabashan area,based on the geochemical analysis data of the samples of Lujiaping Formation in the outcrop area, the geochemical characteristics of the source rocks and the exploration significance of shale gas were discussed. The results show that the source rocks of Lujiaping formation in northern Dabashan area have high organic matter abundance,and the TOC content of the samples ranges from 0.182% to 9.063% with an average value of 3.21%. The organic matter is typeⅠ-Ⅱ1, and mainly comes from bacteria and algae in low salinity shallow water. The vitrinite reflectance(Ro)ranges from 1.36% to 2.56% with an average value of 1.86%,and the peak temperature of rock pyrolysis(Tmax)ranges from 418℃ to 530℃ with an average value of 460℃. The source rocks have entered a high-maturity to over-maturity stage,indicating that it is in the stage of generating moisture or dry gas,and the original hydrocarbon generation potential is good. The dark shale of Lujiaping Formation in northern Dabashan area is thick with high degree of thermal evolution. The fissures and dissolved pores in the source rocks can become the adsorption storage space of shale gas. Favorable areas for shale gas enrichment are expected to be formed when having weak structural area or footwall with good lateral sealing.

Hydrocarbon accumulation models and exploration potential of near-source Cretaceous in the lower assemblage of Melut Basin,South Sudan

SHI Zhongsheng, PANG Wenzhu, CHEN Bintao, XUE Luo, ZHAO Yanjun, MA Lun

2020, Vol.32(5): 23–33 Abstract ( 296 ) PDF (6935 KB) ( 329 )

doi: https://doi.org/10.12108/yxyqc.20200503

In order to study the hydrocarbon accumulation models and exploration potential of the near-source Cretaceous in the lower assemblage of Melut Basin,the petroleum geological analyses of Cretaceous,such as identification of favorable reservoir-caprock assemblage,anatomy of key oil reservoirs,establishment of typical oil reservoir models and analysis of exploration potential, were carried out. The results show that:(1)Three sets of reservoircaprock assemblage were developed in the near-source Cretaceous, including interbedded reservoir-caprock assemblage of sandstones and mudstones in above-source Galhak Formation,inner-generation and inner-accumulation reservoir-caprock assemblage of Al Renk Formation,and upper-generation and lower-accumulation reservoircaprock assemblage of Al Renk and Al Gayger formations.(2)The flooding mudstones are the main controlling factor for the hydrocarbon accumulation of the inner reservoir-caprock assemblage of Galhak Formation,and the inner front of braided river delta is the favorable sedimentary facies for the development of high-production faulted blocks,with thick distributary channel sandstones and thick flooding mudstones.(3)The antithetic faulted blocks of Al Gayger Formation have good oil-source and lateral sealing conditions,and the antithetic faulted blocks with big fault throw in the slope are the preferred drilling targets.(4)The sedimentary facies determine the types and distribution of oil reservoirs in the fans,and the root and middle parts of the fans develop thick sandstones with good physical properties,which are the favorable zones for the development of high-production faultblock and fault-lithological reservoirs.(5)The exploration of the main producing layers in far-source Paleogene gets more and more difficult,and the near-source Cretaceous formations are the important targets for deepening exploration in the mature Northern Sub-basin.(6)The sub-basins in the south Melut Basin have small areas and coarse sediment infillings,which makes the regional caprocks of Adar Formation get worse,and the far-source Paleogene Samma,Yabus and Adar Formations not be favorable reservoir-caprock assemblage. The near-source Cretaceous formations have good accumulation conditions,and are the major exploration formations in the south Melut Basin. The research results have certain guiding significance for the fine exploration in the mature north Melut Basin and regional exploration of Cretaceous in the low-level south Melut Basin.

Main controlling factors of differential enrichment of oil and gas in fault concentrated zones: a case study from Qinan step-fault zone in Qikou Sag

HU Hewei, LI Huiyong, XU Peng, TAO Li, HUA Xiaoli

2020, Vol.32(5): 34–45 Abstract ( 233 ) PDF (7999 KB) ( 282 )

doi: https://doi.org/10.12108/yxyqc.20200504

In order to study the oil and gas accumulation law of Qinan step-fault zone,based on 3D seismic,drilling,logging and core data,through the division of fault concentrated zones and the calculation of cumulative uplift amplitude and the thickness of cap rock juxtaposition,the horizontal and vertical differential enrichment law of shallow oil and gas in Qinan step-fault zone of Bohai Bay Basin was analyzed,and the oil and gas accumulation model was established. The results show that:(1)Flower-like faults,mostly antiformal faults,are well developed and densely distributed in NE and NNE-trending belts of Qinan step-fault zone.(2)Horizontally,oil and gas mainly enrich in the inner and marginal parts of the fault concentrated zones,with enrichment degree being higher in the inner part than that in the marginal part. According to the types of fault concentrated zones,oil and gas are mainly concentrated in the antiformal fault concentrated zones,and the cumulative uplift amplitude in the antiformal fault concentrated zones controls the degree of oil and gas enrichment.(3)Vertically,cap rock juxtaposition thickness of E3d2 controls the oil and gas accumulation in middle and shallow layers of the fault concentrated zones.(4)In the antiformal fault concentrated zones with larger cumulative uplift amplitude and cap rock juxtaposition thickness of E3d2 being less than 50 m,oil and gas can pass through the cap rock of E3d2 and accumulate in the middle and shallow layers. The achievement can provide reference for further exploration and evaluation in the study area.

Development characteristics and evolution of organic matter pores of marine shale in southeastern Chongqing

WANG Pengfei, JIN Can, ZANG Xiaopeng, TIAN Qianning, LIU Guo, CUI Wenjuan

2020, Vol.32(5): 46–53 Abstract ( 288 ) PDF (11088 KB) ( 93 )

doi: https://doi.org/10.12108/yxyqc.20200505

Organic matter pores determine the occurrence and effective flow of hydrocarbon gas in shale reservoir. The organic matter pore structures of typical organic-rich black marine shale with high-over maturity of Lower Silurian Longmaxi Formation and Lower Cambrian Niutitang Formation in southeastern Chongqing were observed by electron microscope. The results show that there were a large number of organic matter pores in pyrobitumen of Longmaxi shale, with large diameter and strong connectivity, and solid kerogen had a little organic matter pores,while no organic matter pore was developed in pyrobitumen and solid kerogen of Niutitang shale. The two sets of shale have similar characteristics in total organic carbon content,whole rock mineral composition and kerogen type,but the thermal maturity of Niutitang shale is much higher than that of Longmaxi shale, and it has reached the metamorphism stage. The physical and chemical properties of solid kerogen and pyrobitumen tend to be similar to that of graphite, resulting in no pores developed in the organic matter. High thermal maturity is not conducive to the preservation of organic pores in shale, so the exploration and development of highover maturity marine shale gas of Lower Cambrian Niutitang Formation in southeastern Chongqing should focus on the area with thermal maturity less than 3.5%.

Sedimentary characteristics and exploration potentials of Lower Cretaceous Xiagou Formation in Ying'er Sag,Jiuquan Basin

WU Qingpeng, LYU Ximin, CHEN Juan, ZHOU Zaihua, YUAN Cheng

2020, Vol.32(5): 54–62 Abstract ( 262 ) PDF (6721 KB) ( 339 )

doi: https://doi.org/10.12108/yxyqc.20200506

In order to explore a new field for oil & gas exploration in Ying'er Sag,the sedimentary characteristics of Xiagou Formation in Ying'er Sag were studied based on the analysis of sedimentary settings,core observation,grain size,well logging,seismic attributes and reservoir prediction. The results show that:A new type of turbidite sand body is developed in the upper Xiagou Formation of Ying'er Sag. The turbidite which is controlled and triggered by the synsedimentary fault can be identified as a deposition of the off-shore subaqueous fan facies. The turbidites in this area are synsedimentary fault-related,small in individual size but large in groups. The discovery of turbidites can further expand the area of lithologic reservoir exploration in Ying'er Sag. It lays a solid foundation for hydrocarbon exploration in the low position of structure and sags which are similar to Ying'er Sag.

Reservoir characteristics and controlling factors of Chang 6 of Yanchang Formation in Wuqi area,Ordos Basin

WANG Peng, SUN Linghui, WANG He, LI Zian

2020, Vol.32(5): 63–72 Abstract ( 333 ) PDF (9867 KB) ( 330 )

doi: https://doi.org/10.12108/yxyqc.20200507

Chang 6 oil reservoir in Wuqi area of Ordos Basin is a set of typical tight-sandstone oil reservoirs. To find out the micro characteristics of the reservoir and analyze the controlling factors that affect the development of the reservoir are helpful to clarify its influence on the accumulation of tight oil. By means of thin section identification, porosity and permeability test,casting thin section, scanning electron microscope and high-pressure mercury injection, the petrological characteristics, physical properties and pore characteristics,pore structure characteristics and reservoir types of Chang 6 reservoir were studied,and the influence of diagenesis on reservoir development was analyzed.The results show that the rock type of Chang 6 reservoiris mainly feldspathic sandstone. The porosity ranges from 6% to 12%, with an average of 9.45%, and the permeability ranges from 0.05 mD to 0.50 mD, with an average of 0.34 mD. The main types of reservoir space include residual intergranular pores and dissolved pores, which have four different kinds of pore structures,and their pore-throat distributionare slightly different. The type Ⅰ samples have more macropores,with peak pore throat radius of 3-5 μm and good pore throat connectivity,followed by type Ⅱ and type Ⅲ samples,and the type IV sample is the worst. The Chang 6 reservoir in Wuqi area is mainly in the late diagenesis stage A. The cementation mainly includes siliceous cementation,clay mineral cementation and carbonate cementation. Among them,chlorite cementation supports more of the pores, and illite cementation and carbonate cementation fill or block the pores. The feldspar,cuttings and interstitials such as turbidities were dissolved,and the formation of secondary dissolved pores significantly improved the reservoir properties.

A new model for sedimentary evolution of fluvial faices based on accommodation space change and its impact on hydrocarbon accumulation: a case study of Kenli-A structure in Laizhouwan Depression

WANG Hang, YANG Haifeng, HUANG Zhen, BAI Bing, GAO Yanfei

2020, Vol.32(5): 73–83 Abstract ( 356 ) PDF (7434 KB) ( 378 )

doi: https://doi.org/10.12108/yxyqc.20200508

In order to clarify the differential accumulation mechanism of Guantao Formation in Laizhouwan Depression,the sequence stratigraphic framework and the sedimentary evolution pattern were established by using sequence stratigraphic theories,core and well-logging analysis and seismic data,and a new model for fluvial facies reservoir characterization was proposed which emphasized the fluctuation of sedimentary base level and the change of accommodation space. The results show that:(1)The Guantao Formation was a third-order sequence,and it was divided into three system tracts including early-stage high accommodation system tract,low accommodation system tract and late-stage high accommodation system tract.(2)Three fluvial facies were recognized in the study area including anastomosing river,braided river and meandering river. Each fluvial facie indicated a distinctive system tract,and the evolutionary process of fluvial facies was affected by the change of system tracts,which resulted in the vertical and lateral distribution differences of reservoir sand bodies.(3)The sand body distribution features of different fluvial facies controlled the hydrocarbon migration and accumulation:the anastomosing river sand bodies which had well lateral connectivity and poor vertical connectivity formed structurallithologic oil reservoir;the braided river sand bodies indicated predominant superimposition with well lateral and vertical connectivity,which became effective pathway for hydrocarbon migration and accumulation in structural high position and formed structural-formation oil reservoir;the meandering river sand bodies which were surrounded by thick mudstone had poor lateral and vertical connectivity,and formed isolated lithologic oil reservoir,thus the coupling relationship of oil-migrating faults and reservoir sand bodies was crucial to hydrocarbon accumulation.

Formation mechanism and distribution prediction of hydrogen sulfide in Yingxiongling area,Qaidam Basin

TIAN Jixian, ZHAO Jian, ZHANG Jing, KONG Hua, FANG Yongsheng, ZENG Xu, SHA Wei, WANG Mu

2020, Vol.32(5): 84–92 Abstract ( 278 ) PDF (4617 KB) ( 363 )

doi: https://doi.org/10.12108/yxyqc.20200509

In recent years,gas reservoirs containing high hydrogen sulfide have been found in lacustrine carbonate rocks in the upper member of the lower Ganchaigou Formation(E32)in Yingxiongling area of Qaidam Basin. In order to clarify the genetic mechanism of hydrogen sulfide and predict its distribution effectively,the geochemical characteristic analysis of natural gas and simulated experiment were carried out. The results show that:(1)Hydrogen sulfide is a product of thermochemical sulphate reduction(TSR)in the central of Yingxiongling area,and the higher the temperature,the greater the production. The development of source rocks,the widely distributed salt-rock formation,the high geothermal gradient and the large number of developed pore reservoirs provide favorable conditions for the formation of hydrogen sulfide gas reservoirs.(2)Under the influence of the overall uplift of the Late Himalayan movement,the maximum paleogeothermal temperature experienced by the present strata in historical accumulation period is higher.(3)During E32 deposition period,the rock salt developed in the center of the lake basin,and the oil and gas sealing conditions are good. The development of the pre-salt pore reservoirs is conducive to the enrichment of hydrogen sulfide. It was comprehensively predicted that the pre-salt strata in the central of Yingxiongling-Ganchaigou area are hydrogen sulfide enrichment areas. The research results are of great significance for the exploration,deployment and production safety of hydrogen sulfide gas reservoir.

Characteristics of micro pore structure and movable fluid of extra-low permeability reservoir: a case study of lower Et1 reservoir in A'er Sag,Erlian Basin

UANG Jie, DU Yuhong, WANG Hongmei, GUO Jia, SHAN Xiaokun, MIAO Xue, ZHONG Xinyu, ZHU Yushuang

2020, Vol.32(5): 93–101 Abstract ( 320 ) PDF (9758 KB) ( 289 )

doi: https://doi.org/10.12108/yxyqc.20200510

In order to make clear the micro pore structure and the occurrence characteristics of movable fluid of the lower Et 1 reservoir in A'er Sag,Erlian Basin,the experimental studies such as SEM,casting slice,X-ray diffraction,high pressure mercury injection,constant velocity mercury injection and NMR were carried out. The results show that:(1)There are three types of micro pore structure of the lower Et1 reservoir,and different pore structures have different characteristics of occurrence of movable fluid.(2) The pore structure of type Ⅰis mainly composed of intergranular pore-pore shrinking throat and intergranular pore-necking throat,with large throat radius and small pore throat radius ratio. Its T2 spectrum of NMR is mainly left low right high bimodal type,and movable fluid saturation is high. The pore structure of type Ⅱ is mainly composed of intergranular pore-flaky throat and dissolved pore-flaky throat,and its T2 spectrum is mainly left high right low bimodal type,with medium movable fluid saturation. The pore structure of type Ⅲ is mainly composed of intergranular pore-flaky throat combination,dissolved pore-flaky throat combination and intercrystalline pore-bundle throat combination. The throat radius of type Ⅲ is small,with T2 spectrum of left single peak type and low movable fluid saturation.(3)The physical properties,micro pore structure and clay mineral content of the reservoir have an important influence on the occurrence of movable fluid. The characteristics of throat are the main factors affecting the occurrence of movable fluid. The larger the throat radius is,the more the large throat is,the higher the saturation of movable fluid is. The research results have guiding significance for the high-efficiency development of lower Et1 reservoir in A'er Sag.

Genesis and corrosion mechanism of zeolite of Lower Urhe Formation of Permian in Mahu Depression

LEI Haiyan, FAN Shun, XIAN Benzhong, MENG Ying, YANG Hongxia, YANG Qi, QI Jing

2020, Vol.32(5): 102–112 Abstract ( 229 ) PDF (12233 KB) ( 281 )

doi: https://doi.org/10.12108/yxyqc.20200511

In order to study the genesis and dissolution mechanism of zeolites in the Lower Urhe Formation of Permian in Mahu Depression,thin section identification,fluorescence analysis,field emission scanning electron microscopy,electron probe analysis,energy spectrum analysis and inclusion test were carried out. The results show that:(1)The mainly zeolite group minerals in the study area are turbidite,followed by heulandite,analcite,clinoptilolite and zeolites. The zeolites have both high-temperature and low-temperature genesis types.(2)The genesis of zeolites mainly includes two types:in the early diagenetic stage,it is dominated by alteration of volcanic materials,and the cores cemented by zeolites are mostly loose and easy to disperse;in the late diagenetic stage, it is dominated by pore water crystallization,and the cores are mostly dense. Heulandite,analcite,clinoptilolite and pyroxene are mainly caused by tuffaceous alteration,while turbidites are caused by tuffaceous alteration and pore water crystallization.(3)On the plane,the type and content distribution of zeolites are controlled by the sedimentary facies,while the dissolution difference is controlled by the supply of organic acids. Most of the laumontite are developed in the thick coarse-grained glutenite of the fan delta front,and most of the heulandite is developed in the tuffaceous conglomerate in the front of the fan delta plain. In the glutenite reservoir in delta front or near fracture development zone near the deep-water source rock development area,the turbidite has high dissolution degree and high-quality reservoir development. The research results can be used to guide the study of zeolites bearing reservoirs and the exploration of oil and gas in the Lower Urhe Formation of Permian in Mahu Depression.

Quantitative characterization of shale nanopore structure: a case study of Wufeng Formation in southeastern Sichuan

GUO Juan, ZHAO Difei, LIANG Xiaobo, YANG Kun, LI Haoxuan, LONG Daixi

2020, Vol.32(5): 113–121 Abstract ( 259 ) PDF (3778 KB) ( 360 )

doi: https://doi.org/10.12108/yxyqc.20200512

In order to explore a new method of shale nanopore structure quantification,taking shale reservoir samples of Wufeng Formation in southeastern Sichuan area as an example,high-resolution nanopore images were obtained by argon ion polishing(AIP)and field emission scanning electron microscopy(FE-SEM). The nanoscale pore images were numerically processed by Adobe Photoshop, Adobe Illustrator,Image J,and the development characteristics and structural parameters of nanopores were quantitatively extracted. The results show that four major types of nanopores are developed in shale reservoirs of Wufeng Formation, including organic pores, mineral intragranular structural pores,mineral intragranular dissolved pores and micro fractures,among which organic pores are the predominant pores. Through image information extraction,the quantitative parameters such as shape factor,roundness,elongation,eccentricity and entropy value for each pore were obtained,and a quantitative characterization method for different types of pores in shale was proposed based on the intersection of different parameters of pores. The study of quantification of nanopores is helpful to provide new approaches for the study on pore structure characterization and formation mechanism of high-quality shale reservoirs.

EXPLORATION TECHNOLOGY

Fracture prediction and modeling based on poststack 3D seismic data: a case study of shallow shale gas reservoir in Taiyang-Dazhai area

WANG Jianjun, LI Jingliang, LI Lin, MA Guangchun, DU Yue, JIANG Yiming, LIU Xiao, YU Yinhua

2020, Vol.32(5): 122–132 Abstract ( 293 ) PDF (11307 KB) ( 372 )

doi: https://doi.org/10.12108/yxyqc.20200513

There are Common problems such as mud loss and high fracturing pressure during drilling in TaiyangDazhai area. The reliability and accuracy of quantitative prediction of fractures by geometric attributes of poststack 3D seismic data are always restricted. A modeling method based on the joint application of fracture seismic facies and discrete fracture deterministic extraction technology was proposed. By using seismic attributes such as dip angle,curvature and discontinuity,unsupervised clustering analysis based on Bayesian probability model was carry out to obtain the best clustering effect and number. The spatial system of fracture was established by vertical time slice scanning method,and all the linear structures traced were cleaned and denoised to simplify the complex geometry structure. The cleaned fractures were gridded and reconstructed. The geometric(topological) parameters of each fracture were calculated and a high-precision discrete fracture model was established. The results show that this method can be used to accurately predict the location of fault and fracture in the process of horizontal well drilling in shallow shale gas block of Taiyang-Dazhai area,and the prediction accuracy of fault and fracture reaches 92%,effectively avoiding drilling mud loss,and providing a strong support for the fracturing design. The identification of fracture seismic facies and the establishment of discrete fracture network model provide an effective basis to solve the complex construction problems during drilling and fracturing of shale gas reservoir in this area.

Preconditioning elastic least-squares reverse time migration

LIU Mengli, XU Xingrong, WANG Xiaowei, HU Shuhua, LIU Jintao

2020, Vol.32(5): 133–142 Abstract ( 249 ) PDF (2927 KB) ( 375 )

doi: https://doi.org/10.12108/yxyqc.20200514

Compared to P-wave seismic exploration,multi-wave seismic exploration can attain more information of underground medium. Elastic reverse time migration is a more accurate method for imaging. Leastsquares inverse time migration(LSRTM)treats the migration imaging as an inversion problem in the sense of least squares, which is a correction of the migration imaging process and results, and can provide reflectance images with higher resolution for lithologic reservoir estimation,which has become the trend of imaging method. Based on the establishment of a linear first-order velocity-stress elastic wave equation,the application of adjoint state method helped to reconstruct the reverse-time migration algorithm,and by introducing the theory of leastsquares and using the inverse of approximate Hessian matrix to precondition the gradient,preconditioning elastic least-squares reverse time migration(P-ELSRTM)was implemented. The numerical tests on SEG/EAGE 2-D salt dome model show that compared with the conventional elastic least-squares reverse time migration(ELSRTM), P-ELSRTM can image with higher resolution,better amplitude preservation and faster convergence. In addition,P-ELSRTM is more adaptable to seismic data with random noise.

OIL AND GAS FIELD DEVELOPMENT

A triple-porosity flow model and its nonlinear flow characteristics with considering quadratic pressure gradient

YU Yan, ZHOU Linlang, GAN Xiaofei, HU Yan, GAN Wenjin, DENG Zhuang

2020, Vol.32(5): 143–150 Abstract ( 227 ) PDF (1723 KB) ( 355 )

doi: https://doi.org/10.12108/yxyqc.20200515

The flow of fluids in naturally fractured-vuggy carbonate reservoirs is of strong nonlinear characteristics;therefore,the nonlinear term in a triple-porosity flow model should not to be ignored. For a naturally fracturedvuggy carbonate reservoir,a nonlinear triple-porosity flow model with the consideration of quadratic pressure gradient was established. By using variable substitution,the model can be linearized,and an analytical solution in Laplace space was obtained. A solution with the numerical inversion in real space of the linearized model were obtained. The nonlinear flow characteristics curves were plotted by programming the model solution. The curves reflect the special stage characteristics of inter-porosity flow from vug to fracture systems and matrix to fracture systems respectively. The influences of the fixed model parameters on the type curves were qualitatively and quantitatively studied,including quadratic pressure gradient nonlinear term,the inter-porosity flow factor of fluid from vug to fracture systems,inter-porosity flow factor of fluid from matrix to fracture systems. Finally,by comparing flow characteristic curves of conventional linear flow model,the difference of linear and nonlinear curves affected by the nonlinear quadratic pressure gradient factor was quantitative studied. The results show that affected by the nonlinear quadratic pressure gradient factor,the nonlinear flow curves obviously deviate from linear flow curves,and the deviations increase with the elapse of time and the increase of the nonlinear quadratic pressure gradient factor. The established triple-porosity flow model with considering quadratic pressure gradient term can be used to describe the porous flow characteristics of fractured-vuggy carbonate reservoir more precisely.

Gas seepage flow law of shale gas reservoirs based on REV-scale lattice Boltzmann method

FU Dongyu, LI Yongming, ZHAO Jinzhou, JIANG Youshi, CHEN Xiyu, XU Wenjun

2020, Vol.32(5): 151–160 Abstract ( 227 ) PDF (3202 KB) ( 449 )

doi: https://doi.org/10.12108/yxyqc.20200516

Shale gas reservoirs are characterized by multi-scale and multi-field transport behaviors owing to the various natural micro-fractures and complex matrix pore structures. In order to study the complex seepage law of shale gas reservoir,a micro-fractured porous medium was reconstructed,the generalized lattice Boltzmann model was modified,and representative elementary volume(REV)scale lattice Boltzmann model(LB model)suitable for simulating the seepage characteristics of shale gas was established. Based on the physical properties of natural micro-fractures and seepage flow characteristics of gas slippage,gas adsorption-desorption and surface diffusion, the sensitivity parameters of the model were analyzed. The results show that the micro-fractures become the main channel for gas flow in the matrix when the natural micro-fractures of shale reservoir are relatively developed, the fracture density is the main parameter affecting the apparent permeability of the reservoir. When the fracture density was increased by 3-4 times,the apparent permeability of the reservoir can be increased by more than 10 times,and the fracture aperture and fracture length have less effect. Knudsen number(Kn) is a primary parameter which has great influence on the shale gas flow behaviors. The Klinkenberg effect become more remarkable due to the increasing Knudsen number,especially when Kn > 0.1,the increase rate of the apparent permeability becomes more significant. Moreover,the increasing adsorbed gas concentration is accounting for the decreasing apparent permeability,particularly in case of the lower pressure. The surface diffusion has great impacts on the gas flow behaviors,the apparent permeability could be 2 to 5 times larger than its counterparts in case the effect of surface diffusion has been ignored. However,the strength of this effect is subject to adsorbed gas concentration. This study could provide some instructive insights into the theoretical research of the shale gas seepage mechanism and some technological support for the exploration and exploitation of shale gas reservoirs.

Miscible displacement simulation with dispersion

QI Tao, HU Yong, LI Qian, ZHAO Zihan, ZHANG Chun, LI Tao

2020, Vol.32(5): 161–169 Abstract ( 192 ) PDF (4009 KB) ( 300 )

doi: https://doi.org/10.12108/yxyqc.20200517

Dispersion is an important mass transfer method in miscible displacement process,which determines volume sweep efficiency to a certain extent. However, dispersion is not considered in many miscible displacement processes. Therefore,the body center network model was built according to the stochastic modeling method. Kirchoff's law and finite difference method were used to solve the coupling of pressure field and concentration field of the model. The dynamic network simulation of miscible displacement was carried out,and the influences of pore structure characteristic parameters and fluid flow parameters on miscible displacement were analyzed. The results show that compared with miscible displacement without dispersion,miscible displacement with dispersion has larger volume sweep efficiency,later breakthrough time of displacement fluid and higher recovery degree corresponding to breakthrough. For the miscible displacement with dispersion,the stronger the heterogeneity of pores(or the lower the connectivity of pores,or the larger the viscosity ratio,or the larger the displacement flow),the more obvious the fingering phenomenon,the lower the volume sweep efficiency,the earlier the breakthrough time of front,and the lower the recovery degree. At the same time,the recovery degree corresponding to the breakthrough is linearly related to the heterogeneity of pores(or the connectivity of pores), and is exponentially related to the viscosity ratio(or displacement velocity). The results are of great significance to clarify the solute transport law and expand the volume sweep efficiency of displacement fluid.

PETROLEUM ENGINEERING

Experiment on evaluation of temporary plugging agent for in-fracture steering fracturing in Shunbei oilfield

ZHANG Xiong, WANG Xiaozhi, GUO Tiankui, ZHAO Haiyang, LI Zhaomin, YANG Bin, QU Zhanqing

2020, Vol.32(5): 170–176 Abstract ( 292 ) PDF (2631 KB) ( 423 )

doi: https://doi.org/10.12108/yxyqc.20200518

Temporary plugging and fracturing in fractures is one of the key technologies for the development of fault-karst reservoirs. This technology can make new fractures break at other places where the fractures have been pressed out,so as to greatly improve the utilization degree of weak channels around the well,increase the fracture complexity,and achieve the purpose of increasing production. The Ordovician reservoir in Shunbei oilfield has a deep buried depth,obvious fracture and hole characteristics,and the temperature can reach 160℃,which leads to the rapid failure of common degradable plugging agent. Therefore,an oil-soluble resin powder was selected and a self degradable particle was developed. Based on the mechanism of bridge plugging,the requirements of particle size ratio and effective temporary plugging thickness were defined,and the stability of plugging agent,degradation at high temperature and expansion after water absorption were evaluated. The strength of temporary plugging diaphragm formed by plugging agent in fractures was evaluated through improved displacement device. Finally, reverse injection was carried out to record the plugging removal. The results show that the oil-soluble resin powder is insoluble in water,acid and alkali,but soluble in oil at any temperature. When the mass ratio of particles with different sizes is 1.0:2.0:2.3,the oil-soluble resin powder temporary plugging partition with a thickness of 14 cm can withstand 10 MPa pressure. A-type self degradable particles are insoluble in acid,alkali,salt and oil, and can self degrade in high-temperature oil or water phase. The A-type self degradable particles temporary plugging diaphragm with a thickness of 16 cm can withstand 10 MPa pressure when the mass ratio of different particles is 1.0:1.3. The research results can provide two kinds of temporary plugging agents for Shunbei oilfield.