Lithologic Reservoirs

Compared with southern China,the shale gas accumulation conditions are more complicated,with more genetic types and greater differences in gas-forming characteristics in northern China. However,the classification of the shale gas genesis in northern China is relatively rough and chaotic,with gas-forming model being different and incomplete. The distribution law and exploration direction are not clear yet. Therefore,it is necessary to gain a deeper research to apply the idea of finding gas directly in southern China. Based on the comprehensive analysis of extensive research and typical anatomy,a three-level classification scheme of shale gas based on genetic mechanism,parent material type and evolution stage was established. Based on this standard,a practical and complete standard template for identifying the genetic types of shale gas was established. It is clear that there are nine different genetic types of shale gas in northern China,such as primary oil-type biogas,secondary coal-type biogas,high-mature-over-mature oil-type gas. Typical samples were selected,and a set of unified and practical quantitative general model reflecting the evolution of shale into gas was established by induction,comparison,fitting,docking and assembling. By analyzing the distribution law of shale gas in northern China,it is concluded there are stratified evolution stages in the longitudinal direction,and ordered continuous distribution features on the plane according to the degree of evolution. It is proposed that the shale gas exploration in the north adopts the principle of "classified exploration,step-by-step implementation,and various breakdowns". Coal shale gas and biogenic shale gas are the main exploration areas,and the mature,high mature-over mature coal shale gas in Mesozoic coal-bearing strata and secondary oil-type bio-shale gas of lacustrine organic mud shale are the key exploration objects. For Cenozoic coal-bearing strata and lacustrine organic shale,the main target is to search for secondary biogenic shale gas and primary biogenic shale gas. The results of this study have a guiding role in the exploration and development of shale gas in northern China.

Mechanism of sealing oil and gas with cap-rocks

LI Chuanliang, ZHU Suyang, LIU Donghua

2019, Vol.31(1): 12–19 Abstract ( 460 ) PDF (2357 KB) ( 641 )

doi: https://doi.org/10.12108/yxyqc.20190102

Underground accumulation of oil and gas is the result of cap-rock's sealing. Without the sealing of caprocks, oil and gas will migrate to the earth's surface and be lost away. Therefore,cap-rocks play an important role in the accumulation of oil and gas. In order to clarify the sealing mechanism of cap-rocks,a deep study was carried out based on the related knowledge of petroleum geology,petrophysics and fluid mechanics,which reached the following conclusions. Cap-rocks seal oil and gas by capillary pressure. The stronger the heterogeneity of formations is,the larger the capillary pressure differential between the cap-rock and the reservoir rock will be, and the more the oil and gas can be sealed by the cap-rocks. Homogeneous formations cannot accumulate oil and gas. The heterogeneity of formations has made the petroleum industry. Oil and gas can migrate from the smaller pores of hydrocarbon source rocks into the larger pores of reservoir rocks,but cannot migrate from the larger pores of reservoir rocks into the smaller pores of cap-rocks,which is the marvelous point of oil and gas migration. The wettability of rocks is also very important. The oil-wet rocks cannot seal oil and gas,while the water-wet rocks can do. The water-wettability of rocks has made the petroleum industry. The hydrocarbon concentration of water is quite low in cap-rocks,being impossibly higher than that in reservoirs,so the hydrocarbon concentration sealing of cap-rocks cannot take place. Cap-rocks can seal oil and gas rather than formation water,and cap-rocks can seal the phase of oil and gas rather than the molecules of oil and gas, which is the marvelous point of sealing mechanism of cap-rocks. Overpressure of cap-rocks is calculated by the equivalent depth method,which is a misleading appearance. Cap-rocks are not really overpressured,so they cannot apply overpressure sealing to oil and gas.

Influence of sedimentary events on deep water sedimentation process: a case of Chang 6 reservoir in Huaqing area,Ordos Basin

FU Qiang, LI Jing, DENG Xiuqin, ZHAO Shijie, PANG Jinlian, MENG Pengfei

2019, Vol.31(1): 20–29 Abstract ( 378 ) PDF (4872 KB) ( 536 )

doi: https://doi.org/10.12108/yxyqc.20190103

The thick sandstone of Chang 6 reservoir in Huaqing area,Ordos Basin,is considered as the result of deep-water deposition. The data of core photographs,wire-logging,mud-logging and rock samples analysis were used to analyze sedimentary process in deep-water area and petrogenesis mechanism,including four main sedimentary events(gravity flow event,volcanic event,seismic event,and hypoxic event)happened in deep-water deposition process in Chang 6 reservoir. The results show that:(1)Gravity flow deposition events occurred frequently during the whole deposition process,which is the direct cause of large-area multi-layer accumulation of sand bodies in the deep-water area.(2)The intensity and influence range of volcanic activity in Chang 6 deposition period is much smaller than that in Chang 7,only with 1.74 m of average thickness of tuffaceous mudstones which are mainly distributed in Chang 62 and Chang 63 sandstone. Based on locations and sizes of tuffaceous mudstone developed,volcanic ash was considered add into the basin by river carrying.(3)The sedimentary tectonic features of core reflect the frequent occurrence of seismic events,and the magnitude of the earthquake is estimated to be about 4.5-5.5.(4)The combination of the above sedimentary events led to the occurrence of hypoxic events during the depositional period,and as a result,the source rocks rich in organic matter were deposited in the deep-water area,which formed a good source-reservoir-cap assemblage with reservoir sand bodies vertically.

Sedimentary characteristics of shallow-water braided delta of Karamay Formation in Mahu area

YANG Fan, CAO Zhenglin, WEI Yanzhao, LU Linlin, WU Aicheng, MA Liya, WANG Ruiju

2019, Vol.31(1): 30–39 Abstract ( 554 ) PDF (8394 KB) ( 509 )

doi: https://doi.org/10.12108/yxyqc.20190104

Recently,several wells of Karamay Formation in Mahu area have obtained industrial oil and gas flow,which shows a favorable exploration potential of middle and shallow strata. In order to find out the characteristics of sedimentary system of Karamay Formation in Mahu area and to clarify the origin and distribution of main sand bodies,core observation,provenance analysis,sedimentary facies study,plane distribution rule and controlling factors of sand bodies were carried out. The results show that:(1)During the sedimentary period of Karamay Formation,Junggar Basin was a depression lacustrine basin,and Mahu area was gradually transformed from a "multi-uplift and multi-depression" to a "large gentle slope" background. Based on this structural background,four provenance systems were developed during the Karamay Formation. The sedimentary facies are mainly shallow braided river delta. The main reservoir types are underwater distributary channel sand bodies in the front of shallow braided river delta.(2)The sand bodies in the lower Karamay Formation are mainly concentrated at the bottom,interbedded with mudstone,and relatively developed in Xiazijie,Huangyangquan and other main provenance areas;(3)The sand bodies in the upper Karamay Formation are mainly developed at the top, and the delta sand bodies deposit in the form of imbrication toward the center of the lacustrine and extend far away. Reservoir-seal assemblage formed by sand bodies of lower Karamay Formation and thick dark mudstone of upper Karamay Formation and reservoir-seal assemblage formed by sand bodies at top of Karamay Formation and huge thick mudstone of Baijiantan Formation are favorable exploration zones. The research results have guiding significance for oil and gas exploration of Karamay Formation in Mahu area.

Sandbody superimposed pattern of meandering river facies of Guantao Formation in Chengdao Oilfield

LIU Li

2019, Vol.31(1): 40–48 Abstract ( 347 ) PDF (9038 KB) ( 500 )

doi: https://doi.org/10.12108/yxyqc.20190105

There are many sets of fluvial facies sandbodies developed in the upper Guantao Formation in Chengdao Oilfield,and the connectivity between the sandbodies is different,resulting in uneven injection and production in the study area. The upper Guantao Formation of Chengdao Oilfield has the characteristics of many high angle holes,large well spacing,rapid change of sandbodies,and limited ability of seismic data to identify single sandbody. On the basis of well-point analysis,a comprehensive identification was carried out combined with wave equation forward modeling and geostatistical inversion,and five configuration models of fluvial sandbodies in Chengdao Oilfield were established. They are separation type and composite superimposed type in vertical and separation type,river bank contact type and cutting and stacking type in lateral. In the vertical direction,the separated channel sandbodies have good connectivity,while composite superimposed sandbodies that are not connected are cut and overlapped between upper and lower layers,with ineffective water injection and rapid production decrease. In the lateral direction,the separated sandbodies are basically disconnected;the river bank contact sandbodies are poor in connectivity and slow in effectiveness;two-stage channel sand bodies of the cutting and stacking type are partially superimposed,and sandbodies with large cutting and stacking thickness have good connectivity,with quick water injection efficiency,while sandbodies between two single channels with small cutting and stacking thickness have poor connectivity. The results provide a basis for realizing balanced injection and production in oilfields.

Reservoir characteristics and favorable areas prediction of coalbed methane in S block,eastern Australia

HUAI Yinchao, ZHANG Ming, TAN Yuhan, WANG Xin

2019, Vol.31(1): 49–56 Abstract ( 2094 ) PDF (3837 KB) ( 453 )

doi: https://doi.org/10.12108/yxyqc.20190106

The mature development technology and large demands of coalbed methane provide favorable conditions for the development of low rank coalbed methane in S block of eastern Australia. However,there is a lack of systematic research on the characteristics of low rank coalbed methane reservoirs. Therefore,the reservoir characteristics such as coal seam development,coal quality characteristics,reservoir physical properties,gasbearing property and preservation condition for low rank CBM were studied by using drilling,logging and core analysis data from S block,eastern Australia. On this basis,a multi-level fuzzy evaluation method was applied to predict favorable areas in S block. The results show that there are six sets of long flame coal with medium-high ash and a cumulative thickness of 25 m are developed in the study areas. Macroscopically,the coal is mainly composed of semi-bright coal and bright coal,the content of vitrinite is the highest in macerals,and vitrine is the dominated microstructure in coal. The pore structure is mainly mesopores and macrospores,cleats and fractures are relatively developed,and the permeability is 399.85 mD. The average gas content is 4.3 m3/t,and good hydrogeological conditions and temperature,pressure system also ensure the enrichment of coalbed methane to a certain extent. The distribution of favorable areas is mainly controlled by gas content,cumulative thickness and permeability. It is considered that the low rank coalbed methane resources in S block of eastern Australia have good potential for development.

Analysis of accumulation conditions of three sets of marine shale gas in southern China

HE Guisong, HE Xipeng, GAO Yuqiao, ZHANG Peixian, WAN Jingya, HUANG Xiaozhen

2019, Vol.31(1): 57–68 Abstract ( 641 ) PDF (6316 KB) ( 557 )

doi: https://doi.org/10.12108/yxyqc.20190107

In order to reveal the exploration potential differences of three sets of regional marine shale in southern China,the accumulation conditions were compared from the aspects of early transformation and post-reformation by using the data of core experiment analysis,drilling,fracturing test of typical wells in southern Guizhou, southeastern Chongqing and central Hunan area. The results show that:(1)Wufeng-Longmaxi Formation is siliceous shale in deep continental shelf of depression basin. It is the most favorable exploration and development layer with excellent potential for hydrocarbon generation,superior reservoir physical properties,high gas content and high formation pressure. High-quality shale thickness,preservation conditions and compressibility are the focus of the selection and evaluation of shale gas.(2)Jiumenchong Formation is interbedded silty-siliceous shale in deep continental shelf of the passive continental margin. It is an important successor layer for shale gas exploration with great potential for hydrocarbon generation,high thermal maturity,relatively poor physical properties,complicated storage conditions and deep burial depth. Thermal evolution degree,structural stability and burial depth are the focus of the selection and evaluation of shale gas.(3)Dalong Formation is interbedded mudstone-calcareous mudstone in deep water platform of rift basin. It is potential favorable layer with great potential for hydrocarbon generation,good physical properties,many interlayers,high clay mineral content,poorly capped roof and floor rocks,and low gas content. Favorable facies zones,continuous thickness of organic-rich shale and compressibility are the focus of the selection and evaluation of shale gas.(4)Wufeng-Longmaxi Formation in central,southern and southeastern Sichuan,Jiumenchong Formation in central Sichuan,southern Guizhou and Yichang areas,and Dalong Formation in Lianyuan area of central Hunan are favorable areas for shale gas exploration and development.

Sweet spot prediction of tight reservoir of He 8 member in Leijiaqi area,eastern margin of Ordos Basin

SUN Wenju, WANG Yingbin, XU Wenjun

2019, Vol.31(1): 69–77 Abstract ( 289 ) PDF (8333 KB) ( 410 )

doi: https://doi.org/10.12108/yxyqc.20190108

Braided river sand bodies are widely developed in He 8 member in Leijiaqi area,eastern margin of Ordos Basin,which is a typical tight sandstone gas reservoir. In order to solve the difficulty of gas reservoir prediction caused by poor quality of seismic data,laboratory core analysis and testing were carried out. The results show that:(1)The reservoir sandstones of He 8 member in Leijiaqi area are mainly lithic sandstone and feldspathic lithic sandstone. The reservoir spaces include residual intergranular pores,intergranular dissolved pores and intragranular dissolved pores. The reservoir is a typical tight sandstone reservoir with low porosity,poor pore throat sorting and complex pore structure.(2)Compaction,pressure dissolution and cementation are the main destructive diagenesis,while dissolution and structural fracturing can effectively improve the reservoir properties.(3)According to the variation of petrophysics parameters caused by different diagenesis,combined with the attributes of sweet spot extracted from 3 D seismic data and Poisson's ratio obtained by simultaneous pre-stack inversion,favorable areas formed by constructive diagenesis can be divided in plane,and gas enrichment areas can be effectively predicted. The drilling results of well LX-41 deployed according to the above methods are consistent with the prediction results. The research results have a certain guiding significance for the prediction of sweet spot in similar zones.

Reservoir characteristics of Changxing-Feixianguan Formation in northeastern Sichuan area

LIU Yanting

2019, Vol.31(1): 78–86 Abstract ( 351 ) PDF (9209 KB) ( 401 )

doi: https://doi.org/10.12108/yxyqc.20190109

In order to study the reservoir characteristics and main controlling factors of reservoir differences in Zhenba and eastern Nanjiang-Heichiliang areas in Heichiliang platform of northeastern Sichuan Basin,the observation and description of outcrops and newly added drilling cores,identification of common and cast thin sections of rocks,reservoir property test and seismic interpretation,were carried out to systematically compare and analyze the reservoir lithology,space,thickness and properties of Changxing-Feixianguan Formation in eastern NanjiangHeichiliang and Zhenba areas from the aspects of sedimentation and diagenesis,and their causes were analyzed. The results show that the two areas have some similarities in reservoir lithology,thickness and reservoir performance,but there are also some differences. Paleogeomorphology,basement faults,diagenesis and tectonism are the key factors causing reservoir differences. The research results can provide geological basis for the next oil and gas exploration in northeastern Sichuan Basin.

Paleoenvironment and controlling factors of organic matter enrichment: a case of Chang 7 oil reservoir in southern margin of Ordos Basin

LI Sen, ZHU Rukai, CUI Jingwei, LIU Han

2019, Vol.31(1): 87–95 Abstract ( 360 ) PDF (3656 KB) ( 551 )

doi: https://doi.org/10.12108/yxyqc.20190110

The organic-rich shales of Chang 7 oil reservoir are widely developed in the southern margin of Ordos Basin,however,the mechanism of organic accumulation in the shales,sedimentary environment and controlling factors are controversial. High-density element scanning and organic geochemical analysis were carried out for Chang 7 member in well Yaoye 1 in Tongchuan area,to reconstruct the paleoenvironment of Chang 7 shales,revealing the controlling factors of organic-rich shale formation. It is found that the paleoproductivity decreased gradually from bottom to top,the water body was brackish and gradually desalinated during Chang 7 sedimentary period,and the water body changed from oxygen-rich to oxygen-poor and then to oxygen-rich. Pyrolysis and organic carbon measurements of organic-rich shales show that the organic matter types include Ⅱ1,Ⅱ2 and Ⅲ,and the abundance of organic matter is 0.44%-26.9%. The characteristics of organic matter in longitudinal direction are quite different. According to the of organic matter characteristics and paleoenvironment parameters of shales, the abundance of organic matter is mainly controlled by the reduction degree of water body,and the type of organic matter is related to paleoproductivity. Volcanic ash plays an active role in improving paleoproductivity.

Key sequence surfaces identification and its significance in the exploration of lithologic reservoirs: a case of Zhujiang Formation in Huizhou Depression

RUI Zhifeng, LIN Changsong, DU Jiayuan, DING Lin, LI Xiao

2019, Vol.31(1): 96–105 Abstract ( 267 ) PDF (10461 KB) ( 634 )

doi: https://doi.org/10.12108/yxyqc.20190111

Sandbody updip pinch-out reservoir is an important target for subtle traps exploration,among which sandbody updip pinch-out trap formed in delta front sandbodies is one of the most important types. In the third-order sequences mainly constituted by delta front sediments,the identification of high-resolution sequence stratigraphic interfaces and the analysis of sequence composition play key roles in understanding the distribution of sandbody updip pinch-out reservoirs and their hydrocarbon exploration. A high-frequency sequence stratigraphic framework consisting of fourth-order sequence was established for Zhujiang Formation in Huizhou area,the Pearl River Mouth Basin. The high-frequency sequence surfaces include two types,which are sedimentary transition surface and secondary flooding surface. The compositional characteristics of the fourth-order sequence are different in different system tracts of the third-order sequence. The fourth-order sequence developed in the transgression system tract consists of complete progradation and retrogradation cycle,while the fourth-order sequence developed in the highstand system tract mostly consists of progradation half-cycle. The formation and distribution of the sandbodies are controlled by the third-order sequence surface and the fourth-order sequence transition surface, and the formation and distribution of the mud layer are controlled by the maximum water flooding surface and the sub-level water flooding surface. The typical "sandwich" structure is composed of top layer,reservoir and floor layer,which overlap vertically. It forms multiple sets of reservoir-seal assemblage for sandbody updip pinch-out cap oil and gas exploration,also controls the planar distribution of lithologic reservoirs.

Prediction of strata depth and hydrocarbon attributes by using VSP multi-wave data

CAI Zhidong, LI Qing, WANG Chong, WANG Yong, FAN Hua

2019, Vol.31(1): 106–112 Abstract ( 323 ) PDF (6451 KB) ( 475 )

doi: https://doi.org/10.12108/yxyqc.20190112

Prediction of pre-drilling strata information is necessary in the process of oil and gas exploration and development. VSP technology is a commonly used prediction method. Traditional VSP method only uses upgoing and downgoing waves to predict the depth of pre-drilled strata,and the accuracy of the predicted stratigraphic depth is limited. So far,few scholars have studied attribute prediction methods based on VSP data. A new method for predicting formation depth and hydrocarbon attributes by using VSP multi-wave information was proposed. This method makes full use of the abundant wave field information of VSP. Firstly,the multiple events related to the target layer were tracked in the data,and according to the tracked result,the discrete function groups were built,and the overdetermined equations were solved separately. Then the statistical weighting method was used to obtain the final prediction depth. This method can reduce the uncertainty of the prediction results and greatly improve the accuracy of the formation depth prediction. After obtaining accurate formation depth data,the differences between compressional wave and shear wave were calculated and used to predict the hydrocarbon attributes. The practical application effect was proved by two examples of VSP projects in western China.

Prediction method of shale formation pressure based on pre-stack inversion

LI Yufeng, SUN Wei, HE Weiwei, YANG Yunfei, ZHANG Xinwen, YAN Yisheng

2019, Vol.31(1): 113–121 Abstract ( 406 ) PDF (3932 KB) ( 612 )

doi: https://doi.org/10.12108/yxyqc.20190113

With the deep exploration and development of shale gas,formation pressure prediction has become an urgent problem to be solved. Taking shale gas reservoir of Silurian Longmaxi Formation in Jiaoshiba area as the research object,the applicability of traditional formation pressure prediction methods was analyzed. Based on the analysis of logging response characteristics of abnormal pressure development zone of shale gas reservoir,a new parameter,namely abnormal formation pressure factor,was proposed to effectively identify abnormal formation pressure of shale gas. The pre-stack elastic impedance inversion result was used to calculate the abnormal formation pressure factor,so as to predict the pressure distribution characteristics of shale formation in Jiaoshiba area. The prediction result of the new method shows higher accuracy than that of the traditional method. This research results can be applied to pressure prediction of shale formation and provide a theoretical reference for fine exploration of shale gas.

Weighted MPFI method and its application in 3D joint processing

XU Xingrong, SU Qin, WANG Jinsong, KOU Longjiang, WEN Yihua, WANG Jing

2019, Vol.31(1): 122–129 Abstract ( 273 ) PDF (5649 KB) ( 446 )

doi: https://doi.org/10.12108/yxyqc.20190114

Conventional regularization methods based on the theories of MPFI,ALFT,Low-Rank and MWNI either cannot effectively overcome spatial aliasing,or cannot satisfy the linear assumption,therefore,they are not effective to achieve fidelity regularization in three-dimensional multi-block joint processing with different acquisition parameters. On the basis of conventional MPFI algorithm,the low-frequency spectrum without false frequency was weighted as prior information,the weighted MPFI data interpolation was realized,and the regularization method was established. The results show that compared with the conventional MPFI method,this method can effectively overcome the spatial aliasing and realize three-dimensional multi-block regularization joint processing. Moreover,it does not add additional geological information,but improves the spatial sampling properties of the observation system to some extent,and has a higher fidelity than the conventional regularization method. The accuracy,validity and adaptability to field seismic data of this method were verified by trial calculation of forward model and field seismic data.

Electrical response characteristics of Fontainebleau sandstone in Paris Basin,France

LI Xiao, LI Min, CHEN Meng, TANG Yanbing

2019, Vol.31(1): 130–138 Abstract ( 320 ) PDF (3942 KB) ( 414 )

doi: https://doi.org/10.12108/yxyqc.20190115

The assessment for oil and gas saturation of reservoir rock is based on acquiring accurate electrical characteristic parameters. Nine samples of Fontainebleau sandstone with different physical properties in Paris Basin of France were selected to carry out laboratory testing of rock electrical parameters. On the basis of percolation theory,a new model was proposed to characterize the electrical characteristics of reservoir rocks,and the experimental data were fitted and analyzed by Archie formula and new model. The results show that the electrical property relationship of high porosity and permeability rock samples matches well with linear relationship of Archie's formula,showing a linear relationship. The electrical property relationship of medium and low permeability rock samples under low water saturation partly deviates from Archie linear relationship,showing obvious non-Archie features. It is considered that the complex micro-pore structure is the main factor inducing the non-linear relationship between the electrical properties of reservoirs and Archie's linear relationship. The saturation index n obtained by Archie formula is 0.948-1.820,which has a good correlation with the square of permeability and a poor correlation with the square of porosity. Cementation index m is 1.6-1.9,and lithology coefficient b is 1.003-1.036,both of which have poor correlations with porosity and permeability. The new model can accurately characterize the non-liner characteristics of rock electrical properties and enrich the evaluation methods of reservoir oil and gas saturation.

A new algorithm for non-gradient optimization of injection-production parameters for polymer flooding

XIE Xiaoqing

2019, Vol.31(1): 139–146 Abstract ( 497 ) PDF (2696 KB) ( 531 )

doi: https://doi.org/10.12108/yxyqc.20190116

Non-gradient optimization algorithm for optimization algorithms theory research is meaningful and has been applied in many practical problems,and it can also be used to solve the optimal control model of injectionproduction parameters for polymer flooding. Aiming at the advantages and disadvantages of finite difference stochastic approximation(FDSA)and simultaneous perturbation stochastic approximation(SPSA),a simultaneous perturbation stochastic approximation algorithm guided by finite difference gradient(SPSA-FDG)was proposed. Based on CMG reservoir numerical simulation software,reservoir numerical simulation model was established, by using the SPSA-FDG,optimal control study of injection-production parameters for polymer flooding was carried out,and the optimized results with the three algorithms were analyzed. The results show that the convergence of SPSA-FDG algorithm is better than that of FDSA and SPSA algorithm,and it is easy to combine with any reservoir numerical simulator to solve the optimal control problem of polymer flooding. Compared with uniform polymer flooding scheme,it is found that by using the optimized scheme calculated by SPSA-FDG algorithm,polymer flooding efficiency time is ahead of schedule,the water cut drop funnel is deepened,the cumulative recovery degree is improved,and the overall reservoir development effect is better. SPSA-FDG algorithm can be applied in other chemical flooding fields to improve the effect of chemical flooding.

Prediction of water breakthrough time for horizontal well in non-Darcy flow edge water gas reservoirs

HUANG Quanhua, LIN Xingyu, TONG Kai, LU Yun, FU Yunhui

2019, Vol.31(1): 147–152 Abstract ( 253 ) PDF (2205 KB) ( 414 )

doi: https://doi.org/10.12108/yxyqc.20190117

Reasonable prediction of water breakthrough time of horizontal wells in edge water gas reservoirs is beneficial to rational development of gas reservoirs and evaluation of gas reservoirs. In current prediction models, gas seepage in formation is generally assumed to be Darcy flow,but for high-yield horizontal wells,the non-Darcy effect of fluid seepage in formation on water breakthrough time cannot be ignored. In order to study water breakthrough time more coincident with actual production,based on particle seepage law of porous media fluid,an ellipsoidal horizontal well seepage model was adopted to comprehensively consider the effects of non-Darcy flow effect of gas seepage in high-yield horizontal wells,the distance between horizontal well and initial gas-water interface,the length of horizontal section and the production of gas wells on water breakthrough time,and a formula for predicting water breakthrough time of edge water gas reservoirs with approximate linear supply boundary was derived. The water breakthrough time of a specific horizontal well was calculated,and the related influencing factors were analyzed. The results show that the breakthrough time of edge water increases with the increase of the length of horizontal section;the breakthrough time decreases with the increase of gas well production,and the speed of reduction increases gradually. Compared with the prediction formula of water breakthrough time of gas wells without considering non-Darcy effect,the calculation accuracy of this formula is higher and more coincident with actual production. The research results have a guiding role in the scientific and efficient development of edge water gas reservoirs.

Dynamic reserves calculated by linear relationship in the early development of water-drive gas reservoir

LU Kefeng, MA Lian, LIU Binbin, LI Ning, LIU Qinan, SONG Gangxiang

2019, Vol.31(1): 153–158 Abstract ( 242 ) PDF (1719 KB) ( 286 )

doi: https://doi.org/10.12108/yxyqc.20190118

According to existing references,in the early development stage,water-drive gas reservoir has similar pressure drop characteristics with constant volume gas reservoir,therefore the dynamic reserves of gas reservoir can be obtained by linear relationship pressure drop extrapolation methods. However,the applicable range of gas recovery degree and the calculated dynamic reserve error have not been evaluated. Based on material balance equation and unsteady state aquifer model,the variation of reserve error with gas recovery degree under different aquifer multiplier and water permeability was calculated by iteration algorithm method. The results show that, taking dynamic reserve error less than 10% as criterion,the gas recovery range suitable for the early reserves calculated by linear relationship in water drive gas reservoirs is very narrow,generally less than 5%. Taking waterdrive gas reservoir in Xihu Sag of East China Sea as an example,the differences between the conventionally used method of pressure monitoring and the method of real-time pressure monitoring in obtaining early dynamic reserves by linear relationship were compared. Because of the long-time interval of pressure monitoring,the former method is liable to lead to misjudgment of the linear part of p/Z vs cumulative production in the initial production stage and the deviation in the evaluation of dynamic reserves. The latter method can accurately determine the starting time of the water influx so as to use straight-line extrapolation method to calculate dynamic reserves of water-drive gas reservoirs. The research result has significantly guidance for correct evaluation of dynamic reserves of water-drive gas reservoir in the early development stage.

Plugging mechanism of large size profile control particles and deep migration performance

CHEN Yuhao, WANG Keliang, LI Gen, LU Chunjing

2019, Vol.31(1): 159–164 Abstract ( 399 ) PDF (1954 KB) ( 438 )

doi: https://doi.org/10.12108/yxyqc.20190119

Large size elastic profile control particle is different from conventional profile control agent. It can effectively improve the heterogeneity of deep formation by reasonable use. However,due to the limitation of experimental equipment,the laboratory injection experiment of large size particles is limited. In order to solve this problem,fracture model and particle displacement device were made,and a kind of plugging and deep migration performance evaluation experiment of elastic profile control particle with particle size of 1-5 mm was designed based on field application. Based on the pressure data that were recorded by pressure sensors connected to the displacement device,pressure-time curves were drawn and relevant data analysis methods were summarized. The particle deformation through pressure was proposed to evaluate the deep migration ability and plugging ability of particle,and the effects of particle content on plugging and migration were investigated by changing the content of particles in the profile agent system. The experiment results show that the higher the particle content in profile control particle system,the better the effect of plugging and deep migration. The migration ability of 1 mm particle is stronger and the plugging ability of 3 mm particle is stronger. Both 1 mm particle and 3 mm particle can be applied to the deep profile control. The rigid plugging ability of 5 mm particle diameter is so strong that it's not suitable for the deep profile control. In field application,the particle selection should be carried out in combination with the geological condition of the target block and the purpose of the profile control. The design of the experiment and the corresponding analysis method are simple and effective,and the required devices are easier to obtain. This experimental method can be used for reference in laboratory experiments on the performance of similar large size profile control particles.