Lithologic Reservoirs

A major breakthrough has been made in the exploration of andesite reservoirs developed in Wulanhua Sag of Erlian Basin. However, the andesite reservoir is characterized by strong heterogeneity, difficult reservoir prediction, and difficulty in fine description spatial distribution, which restricts the exploration of this kind of reservoir. Based on the analysis of geological genesis of andesite reservoir formation in the study area, the distribution characteristics of andesite lithofacies and effective reservoir prediction methods were comprehensively studied by means of seismic and geological interpretation, core, logging and seismic attribute analysis. The results show that the crater is mainly located on the basin-controlling (sedimentary)fault zone, with beaded-like distribution. It is speculated that the volcano was erupted in the form of fissure or center-fissure (source-controlling). According to the degree of stomatal development of andesite, the andesite facies in the study area was divided into near crater facies, middle crater facies and far crater facies, and the plane distribution (facies control)of different lithofacies in the study area was defined. On this basis, a seismic inversion technique based on phased-controlled modeling was proposed to remove low-frequency backgrounds, and the effective andesite reservoir distribution was defined. The results show that the middle crater facies is the most favorable facies for stomata development in andesite, the effective andesite reservoirs are mainly distributed along the NE-trending fault belt, and the predicted results are consistent with the drilled wells. This study provides a new idea and method for the prediction of effective andesite reservoirs, and is of great significance for the study of volcanic reservoirs in similar areas.

Adsorptivity of shale under the formation temperature and pressure: a case of Longmaxi Formation in northeastern Chongqing

YU Chuan, ZHOU Xun, FANG Guangjian, WANG Shengxiu, YU Zhongqiang

2018, Vol.30(6): 10–17 Abstract ( 329 ) PDF (2543 KB) ( 656 )

doi: https://doi.org/10.12108/yxyqc.20180602

Adsorptivity is a typical characteristic of shale gas reservoir and a key impact factor of shale gas content. The change rule of shale adsorptivity under the formation temperature and pressure was simulated by a heterothermal adsorption experiment with a case of Lower Silurian Longmaxi shale in northeastern Chongqing, so as to provide theoretical basis for shale gas exploration in this area. The result shows that organic matter is the main internal factor which impacts shale adsorptivity of Longmaxi Formation and the TOC content has a very positive correlation with the adsorption capacity of shale. The geological conditions of temperature and pressure are the external factors which impact shale adsorptivity. Temperature and pressure are mutual inhibitory for shale adsorptivity. With the increase of temperature and pressure, the variation tendency of shale adsorption capacity is similar to parabola. When temperature and pressure are relatively low, pressure plays a leading role, while temperature plays a leading role when temperature and pressure are relatively high. Under the underground condition, the best adsorption state of shale needs to achieve an appropriate matching of temperature, pressure and burial depth). The experimental simulation results show that the optimum theoretical adsorption state of Longmaxi shale in northeastern Chongqing should be at the depth of 1 000-4 500 m.

Development characteristics of igneous rocks and its role in hydrocarbon accumulation in Hari Sag, Yingen-Ejinaqi Basin

BAI Xiaoyin, HAN Changchun, HE Yonghong, REN Laiyi, MA Fangxia, CHEN Zhijun, LIU Huchuang

2018, Vol.30(6): 18–26 Abstract ( 388 ) PDF (8062 KB) ( 676 )

doi: https://doi.org/10.12108/yxyqc.20180603

The Hari Sag is a small fault depression in northern Yingen-Ejinaqi Basin, with low exploration degree, complex lithology and widely developed igneous rocks. In order to further clarify the development characteristics of igneous rock and their influences on hydrocarbon accumulation in the study area, the mineral characteristics, zircon U-Pb chronology, seismic facies, development period and eruption model of igneous rocks were studied, and the influences of volcanic activities on hydrocarbon accumulation in Hari Sag were analyzed in combination with exploration practice. The results show that: (1)There are many types of igneous rocks developed in the study area such as volcanic breccia, tuff, basalt, dacite and andesite. The seismic reflection characteristics are mainly manifested in three types of mainly mound-like seismic facies, cone-shaped seismic facies and parallel plate-like seismic facies. (2)According to the comprehensive study of zircon dating and seismic facies of igneous rocks, there are three stages of volcanic activity in the study area since Late Paleozoic, which are Late Permian, Early Cretaceous Bayingobi Formation and Suhongtu Formation, and the first two stages are central eruption mode, while the latter is typical cracked eruption model. (3)Multi-stage volcanic activity and continuous magmatic hydrothermal activity promoted the rapid maturation of organic matters in source rocks and dolomitization of reservoirs. (4)Igneous rocks with good matching relationship with source rocks and pore and micro-fracture developed are favorable areas for oil and gas exploration. The research results will provide guidance for understanding the characteristics of igneous rocks and the next step of oil and gas exploration and deployment.

Sensitivity of tight sandstone reservoir of Bashijiqike Formation in Keshen area, Tarim Basin

REN Dazhong, ZHANG Hui, ZHOU Ran, WANG Qian, HUANG Hai, TANG Shenglan, JIN Na

2018, Vol.30(6): 27–36 Abstract ( 352 ) PDF (7110 KB) ( 425 )

doi: https://doi.org/10.12108/yxyqc.20180604

Natural productivity of tight sandstone reservoir is lower than that of conventional reservoir and improving the injection method of water flooding is able to enhance oil and gas production efficiently. Thus, the control of physicochemical index and injection parameters of fluid is vital for reasonable and effective reservoir development. Taking tight sandstone reservoir of Cretaceous Bashijiqike Formation in Keshen area of Tarim Basin as an example, the data of casting thin slices, scanning electron microscope, X-ray diffraction and high-pressure mercury injection test were used to conduct reservoir classification based on pore structure. Typical samples were selected to carry out sensitivity evaluation experiments, and the factors affecting the sensitivity of different types of reservoirs were analyzed. The results show that the reservoirs can be divided into three types according to the types of pore assemblages:residual intergranular pores, dissolved pores and microfractures, and the effective reservoir space decreased in turn. The reservoirs have the characteristics of strong water sensitivity, velocity sensitivity and alkali sensitivity, medium-strong saline sensitivity and medium acid sensitivity. The sensitivity is closely related to the sensitivity of reservoir debris and clay minerals. Only samples with high contents of illite can enhance the velocity sensitivity and water sensitivity, alkali sensitivity is controlled by selective dissolution of quartz, and high content of zeolite is an important factor for improving reservoir acid sensitivity. Different types of reservoirs respond differently to the sensitivity. The sensitivity of residual intergranular reservoirs is less affected by pore structure. The throats of dissolved pore reservoirs and micro-fractured reservoirs are more likely to be filled, resulting in a significant decrease in seepage capacity. The research results can provide reference for the effective development of tight sandstone reservoirs.

Depositional models and lithologic reservoir exploration of sandy beach-bar around buried-hill: a case from Galhak Formation in Ruman region of Melut Basin, South Sudan

CHEN Bintao, SHI Zhongsheng, XUE Luo, MA Lun, ZHAO Yanjun, HE Weiwei, WANG Lei, SHI Jianglong

2018, Vol.30(6): 37–44 Abstract ( 406 ) PDF (6609 KB) ( 635 )

doi: https://doi.org/10.12108/yxyqc.20180605

After almost 20 years' exploration, only a few structural traps were left for drilling in Melut Basin, South Sudan. Exploration for new areas such as lithologic reservoirs is needed to tackle the reserve and production decline. Based on analysis of palaeogeomorphic reconstruction, provenance system, mico-facies in single well, sandbodies distribution and investigation of modern deposition in Qinghai Lake, large-scale sandy beach-bars were discovered in Cretaceous Galhak Formation around Ruman buried-hill in Melut Basin. Two depositional models of buried-hill periphery and underwater buried-hill platform were built, and high energy shore and shallow lake environment caused by buried-hill topography located beside the long axis delta was considered as the main controlling factor of sandy beach-bar deposition. In the initial stage of Galhak Formation deposition, Ruman buried hill exposed for a short duration because of intense tilting of faults, where large scale of sandy bar was developed with an area of 10 km2 and a thickness of 10-20 m, the sediment source was provided by basement and long-axis delta. Ruman burial hill was sinking into the water as the relative lake level rising, sandy beach-bars of underwater buried hill platform (dominated by large area of thin layer beach-sand with thick bar-sand in local)were developed, the sediments source was supplied by long-axis delta. Beach-bar sandbodies, up-dipping pinched-out boundary, underlying source rock of Renk Formation, flooding mudstone in the top and lateral lacustrine mudstone seal were matched to form lithological traps. The discovery of sandy beach-bar guided the lithologic reservoir exploration effectively, several exploratory wells that were deployed on the basis of "beach bar" were succeeded, promoting the reserve scale of Ruman area.

Fracture genesis mechanism and geological significance of E₃² in Yingxi area, Qaidam Basin

LI Xiang, WANG Jiangong, ZHANG Ping, LI Lin, HUANG Chenggang, WU Kunyu, ZHANG Qinghui, LONG Wei

2018, Vol.30(6): 45–54 Abstract ( 337 ) PDF (11271 KB) ( 702 )

doi: https://doi.org/10.12108/yxyqc.20180606

In recent years, a continuous breakthrough of low porosity and ultra-low permeability hydrocarbon reservoir exploration of the upper member of the Xiaganchaigou Formation (E32)in Yingxi area of Qaidam Basin has been made. The exploration works identified that enrichment and high yield of oil & gas were related to the fracture system in this area. Therefore, it is of great geological significance to clarify the fracture genesis mechanism. Based on the matching relationship among petrological characteristics, physical properties, self-source overpressure and fractures, and combined with the relationship between different fractures and oil & gas yield, tectonic and salt rock simulation experiment, rock physics experiment, the prediction method of abnormal high-pressure reservoir in Yingxi area was proposed. The results show that: (1)The complex multi-period tectonic movement formed a large number of structural fractures, but most of them were filled with anhydrite. (2)Good hydrocarbon source rocks buried in deeper part of this stratum were fractured by overpressure that formed during the hydrocarbon generation and expulsion processes. At the same time, the overpressure and fractures were preserved by stable salt seal layer developed in the upper part of the stratum, leading to form a giant number of effective fractures that acted as oil & gas migration pathways. (3)Based on the genesis mechanism and model of effective fracture, seismic attributes, salt rock thickness, overpressure distribution law and palaeogeomorphologic features, the distribution of oil & gas enrichment and high yield areas could be predicted accurately. This study acted an important guiding significance for the oil and gas exploration of tight carbonate reservoirs in this area.

A new reservoir sand body resulted from interaction between turbidity flows and bottom currents: a case from Beijiao Sag of Qiongdongnan Basin

LI Yufeng, PU Renhai, TANG Ming, YUAN Chao, WU Shijiu

2018, Vol.30(6): 55–66 Abstract ( 312 ) PDF (11025 KB) ( 525 )

doi: https://doi.org/10.12108/yxyqc.20180607

Nowadays, geologists have mainly focused on channels originated from turbidite flows and perpendicular to continental margin slope, of which the field is now mature. In the deep-water environment, there is pervasive phenomenon for interaction between bottom currents and turbidity flows, of which the study is less. The interaction, resulting in parallel-slope channels, needs to be further researched urgently. Parallel-slope channels, however, are in the initial stage of research. The paleogeomorphology of Beijiao Sag was studied by using 2 D seismic data. Then the time-domain structure and root-mean-square amplitude of 3 D seismic data were used to comprehensively study the high-amplitude parallel-slope channels combined with the seismic profiles of 3 D region, sedimentary environment, sea level change and paleoclimate. The results show that Beijiao Sag was narrow-pathway shaped paleotopography in the Mid-Miocene. A parallel-slope channel with high amplitude was mainly distributed on the right side of narrow pathway in the northeastern Beijiao Sag, exhibiting multi-finger shaped or coneshaped. There was a progradation seismic reflection along the channel, and there were similar progradation seismic reflections and parallel-filling seismic reflections at the head and middle-tail of the channel in the crossing profile of channels, respectively. There was no tectonic fault beneath the parallel-slope in underlying strata. The parallelslope channel is a sedimentary result of interaction between turbidity flows and bottom currents associated with intermediate water, in the process of which fined grained debris such as mud was carried away by bottom currents and coarse-grained debris such as sand was deposited and filled within the channels. The channel is a new type of lithologic reservoir sandbody characterized by high porosity and high permeability. Finally, the main controlling factors consisting of paleoclimate and special paleotopography were analyzed and their sedimentary model was proposed. The channel has important paleoceanic and paleoclimate significance, which not only enriches the type of deep-water sandbody in China, but also is a potential replacement area for deep-water oil and gas exploration in the South China Sea. The channels should be paid attention to by petroleum geologists.

Influences of gypsum-salt deposition on gas accumulation of the fifth member of Majiagou Formation in Ordos Basin

SUN Yujing, ZHOU Lifa

2018, Vol.30(6): 67–75 Abstract ( 297 ) PDF (4461 KB) ( 616 )

doi: https://doi.org/10.12108/yxyqc.20180608

The fifth member of Majiagou Formation (Ma 5 member)is the main gas exploration layer of Ordovician in Ordos Basin. Studying the influences of gypsum-salt deposition on gas accumulation is helpful to the further exploration and development of gas field. The data of cores, thin sections and other statistical analysis were used to study the lithology characteristics and genesis of gypsum-salt rocks of Ma 5 member, as well as its influences on gas reservoir. The results show that the gypsum-salt rocks in Ma 5 member mainly consist of gypsum and gypsum karst breccia, which belong to evaporative genesis. The deposition of gypsum-salt rocks in Ma 5 member is conducive to the organic matter preservation and hydrocarbon generation, and to maintaining and improving the porosity of the lower strata. It also has good sealing ability, and is beneficial for the migration, accumulation and preservation of gas. It is believed that the gypsum-salt deposition in Ma 5 member plays a significant role in the formation of gas reservoirs. This research result is of great importance for the study on the influences of gypsum-salt deposition on natural gas accumulation in similar areas.

Fractal characteristics of pore structure and permeability calculation for tight sandstone reservoirs: a case of Penglaizhen Formation and Shaximiao Formation in Western Sichuan Depression

DENG Haoyang, SIMA Liqiang, WU Wen, LIU Fanglin, WANG Xin, WANG Chao, YANG Guodong

2018, Vol.30(6): 76–82 Abstract ( 381 ) PDF (1934 KB) ( 676 )

doi: https://doi.org/10.12108/yxyqc.20180609

In order to clarify the influence of fractal dimension on macroscopic reservoir physical properties and improve permeability calculation accuracy, high pressure mercury injection experiments were carried out on 12 cores of tight sandstone gas reservoirs in Penglaizhen and Shaximiao Formation in Western Sichuan Depression. All the curves of mercury intrusion were processed by fractal model based on capillary tubes. Combined with poro-sity and permeability, the correlation between fractal dimension and pore structure parameters was analyzed. Through theoretical analysis and many times of trial, Dave, Pf and R50 were finally selected to calculate permeabi-lity by multiple nonlinear regression. The results show that the pore structure in tight sandstone could be divided into four types. The pore structures of big and small pores are relatively independent, and the relationships between fractal dimensions and pore structure parameters are complex. The calculated permeability by multiple nonlinear regression shows strong correlation with measured permeability, whose correlation coefficient squared is more than 0.9. The established model by multiple nonlinear regression shows more accurate in permeability calculation and it provides another thought for permeability calculation.

Well constrained anisotropic velocity model building based on full-azimuth angle gathers and imaging

LIU Wenqing, WANG Xiao, HU Shuhua, ZHANG Tao, JIN Baozhong

2018, Vol.30(6): 83–88 Abstract ( 269 ) PDF (4874 KB) ( 461 )

doi: https://doi.org/10.12108/yxyqc.20180610

For TTI media anisotropic imaging, accurate anisotropy parameter model building is very important. Anisotropy must be considered in seismic imaging with the rapidly development of wide-azimuth acquisition. A set of joint model building method based on well data and full-azimuth angle gathers were proposed. First, Walkaway VSP data and well data can be used to obtain the anisotropy parameters δ volume. Full azimuth angle gathers can be used to obtain RMO information on the anisotropy. Based on well data and full-azimuth angle gathers, anisotropic parameters ε and δ iterative optimization process were established. The proposed solution was tested on field seismic data and the results showed favorable effect in fracture detection and seismic imaging which proved the applicability and effectiveness of the proposed method.

Seismic identification of narrow and thin channel sandbodies of the second member of Guantao Formation in Matouying Uplift

ZHANG Jiankun, WU Xin, FANG Du, WANG Fanglu, GAO Wenzhong, CHEN Xiaojun

2018, Vol.30(6): 89–97 Abstract ( 297 ) PDF (8372 KB) ( 555 )

doi: https://doi.org/10.12108/yxyqc.20180611

Channel sandbody of the second member of Guantao Formation is narrow and thin in Matouying Uplift, which makes it difficult to identify on seismic section. A series of techniques were used, such as pre-stack time migration (PSTM), palaeogeomorphologic reconstruction, high-frequency isochronal stratigraphic division, wireline log facies analysis, channel sandbodies tracking with line drawings of seismic section, strata-bound wave impedance inversion and seismic amplitude strata slices etc. The result shows that the vertical resolution and spatial resolu-tion of seismic data are improved by reducing the grid bin from 15 m×30 m to 7.5 m×7.5 m in PSTM processing. Ng2 is characterized by the obvious "dual structure" of meandering channel, which display the thin interbedded layers of sandstone and mudstone. The sand bodies is controlled by short-term sedimentary cycle, and develop in the lower-middle part of short-term base-level rising hemi-cycles and upper part of short-term base-level descen-ding hemi-cycle. An analysis of seismic facies in Ng2 Ⅴ sand unit reveals that amplitude or wave impedance anomalies with channel forms, irregular arc shape show NE-SW and near NS distributed geomorphologic systems, indicating channel and point-bar complex depositions of meandering river system. The results manifest that the predicted results are consistent well with the actual drilling, and the channel distribution laws are in accordance with regional geological laws, demonstrating that seismic identification for thin channel sand body are true and reliable.

Characteristics and geological genesis of anomalous seismic facies of Penglaiba Formation in Tahe Oilfield

YUAN Yaxuan, FAN Tailiang, YUAN Xuejun, ZHANG Hehang, WANG Jiabei, LUO Cheng, YAN Xinyu

2018, Vol.30(6): 98–108 Abstract ( 291 ) PDF (9389 KB) ( 794 )

doi: https://doi.org/10.12108/yxyqc.20180612

In order to find high-quality dolomite reservoirs of the Ordovician Penglaiba Formation in Tahe Oilfield, three-dimensional seismic data and forward modeling were used to identify the anomalous seismic features, and geological genesis analysis was carried out. The results show that: (1)the anomalous seismic facies of Penglaiba Formation are characterized by multi-layered, short-continuous strong reflection, massive or layered external forms, distributed on one or both sides of faults, longitudinally constrained by horizon, and mostly terminated under the unconformity surface at the top of Penglaiba Formation. (2)The strong reflection seismic facies generally developed in the main part of the structure, and there are three favorable zones on the plane, which are relatively developed in the north-central and northwestern Tahe Oilfield. The distribution direction is consistent with deepfaults, showing NE and NNW directions. (3)Fault-hydrothermal process is the main genetic mechanism of the strong reflection seismic facies which is macroscopically controlled by tectonic framework and developed in the high part of structure. The deep faults are the main transport channels of hydrothermal fluids and terminate upwards in the overlying tight caprock. Therefore, high-quality dolomite reservoirs developed in Penglaiba Formation are of hydrothermal genesis, and the strong seismic reflection is an important seismic identification mark for high-quality dolomite reservoirs.

Diagenetic facies types of tight reservoir and its effects on productivity: a case of Chang 8 reservoir in Jiangjiachuan area, Ordos Basin

XU Bo, WANG Jian, YU Ledan, WANG Kaize, DONG Fengjuan, LIU Feng

2018, Vol.30(6): 109–116 Abstract ( 318 ) PDF (7003 KB) ( 511 )

doi: https://doi.org/10.12108/yxyqc.20180613

Chang 8 reservoir in Jiangjiachuan area in southeast Ordos Basin belongs to near-source hydrocarbon accumulation without long-distance hydrocarbon migration. It is a typical tight oil sandstone reservoir with extralow porosity and ultra-low permeability. It is helpful for reservoir exploration and development through analyzing reservoir diagenetic facies and looking for favorable belt controlled by diagenetic facies. The test and analysis data of casting thin slice, scanning electron microscope, XRD data and cathode luminescence were used to study petrology characteristics, diagenesis types and diagenetic period. Based on the data of oilfield production, the characteristics and differences of different diagenetic facies and their influences on productivity were analyzed, and the favorable diagenetic facies distribution was predicted. The results show that Chang 8 reservoir is mainly composed of lithic arkose sandstone. Compaction and cementation seriously destroyed the primary pore structure of sandstone. Cementation of iron calcite and ferric dolomite is the decisive factor for the tight of the reservoir, and the dissolution in the diagenetic stage is beneficial to the improvement of the porosity and permeability of the reservoir. Most of the reservoirs were under the middle diagenetic stage A, part reservoir is under the early diagenetic stage B. The diagenetic facies can be divided into four types, including intergranular pore and feldspar dissolution diagenetic phase formed by chlorite cementation, intergranular pore and feldspar dissolution diagenetic phase formed by chlorite and illite cementation, feldspar dissolution diagenetic phase formed by illite cementation, and carbonate cementation phase. The favorable belt with good physical properties and maximum oil production is considered as the intergranular pore and feldspar dissolution diagenetic phase formed by chlorite cementation. This research result can provide practical reference for favorable reservoir prediction and efficient development in the study area.

Production split method restricted synthetically by multi-factors in thin interbed sandstone reservoirs

YANG Zhaoping, YUE Shijun, ZHENG Changlong, LIU Xiongzhi, CHEN Gengxin

2018, Vol.30(6): 117–124 Abstract ( 236 ) PDF (4023 KB) ( 525 )

doi: https://doi.org/10.12108/yxyqc.20180614

For the problem of production split in thin interbed sandstone reservoirs with multi-layer commingled production, the accuracy of calculation results obtained by conventional production split method is poor. In order to solve this problem, the following measures can be adopted: (1)Determining production split calculation nodes by using various dynamic and static data (including interlayer heterogeneity, production data, liquid production profile)and production data such as zonal isolation and reperforate. (2)According to perforation and putting into production, elastic production period, zonal isolation and reperforate, liquid production profile test, to determine calculation methods of different types of nodal points separately, obeying the rule of "linearity interpolation between nodal points, and linearity extrapolation outside last nodal point". (3)The calculation procedure of produc-tion split was established. Using the above measurements, the produced oil and water quantity were split accurately for more than 200 wells in Gasi area in Qaidam Basin. The results of production split coincide well with actual production situation and liquid production profile test data. This method improves the accuracy of production split results and enhances work efficiency.

Improvement of characterization method based on type A water drive curve

LING Haochuan, MENG Zhiqiang, SHI Hongfu, SUN Qiang, PAN Jie

2018, Vol.30(6): 125–130 Abstract ( 271 ) PDF (1650 KB) ( 589 )

doi: https://doi.org/10.12108/yxyqc.20180615

Type A water drive curve can be approximated to hyperbolic decline curve by Taylor expansion method to study the law of reservoir production decline. This method only has second-order precision in the neighborhood of initial oil cut, resulting in a large error in the late production prediction. In order to establish the relationship between the type A water drive curve and Arps decline law, and to improve the calculation accuracy of forecasting annual production of oilfields by the type A water drive curve, by comparing and analyzing the decline rate formulas of commonly used water drive curves, an oil cut power function fitting method for the decline rate of the type A water drive curve was proposed. The error of the oil cut power function fitting in different water cut stages was obtained by using the method of minimum value analysis of variance function. The results show that the higher the water cut is, the smaller the error of the oil cut power function fitting is, and when the water cut is greater than 70%, the oil cut power function fitting of the type A water drive curve not only fit better in the neighborhood of initial oil cut but also fit best in overall prediction time. The improved oil cut power function fitting method can be used to predict the annual oil production of the type A water drive curve quickly. The application proves the high accuracy of this method, and it is suitable for predicting the production of reservoirs with water cut greater than 70% which conform to the characteristics of type A water drive.

Dynamical characteristics of inclined well in dual medium low permeability reservoir

JIANG Ruizhong, SHEN Zeyang, CUI Yongzheng, ZHANG Fulei, ZHANG Chunguang, YUAN Jianwei

2018, Vol.30(6): 131–137 Abstract ( 299 ) PDF (1959 KB) ( 415 )

doi: https://doi.org/10.12108/yxyqc.20180616

Inclined wells have been widely used in the development of reservoirs, but the well test interpretation techniques in inclined wells are currently less studied. At the same time, considering the phenomenon of stresssensitivity effect and threshold pressure gradient in low permeability reservoirs, we introduced permeability modulus and threshold pressure gradient to establish a mathematical model of inclined well in dual-medium low-permeability reservoir. By using sink source superposition and Green function, the bottom hole pressure response of this model was obtained and the plots of inclined well test curves were drawn. The results show that:the well test curve can be divided into six flow sections:wellbore storage section, transition flow section, well inclination control section, crack radial flow section, cross flow section and late radial flow section. In addition, the effect of threshold pressure gradient or stress-sensitivity effect led to a sharp upturn in the later stages of the pressure and the derivative curve, and the upturns caused by the effect of threshold pressure gradient was relatively larger. Otherwise, considering these two factors at the same time, their effects overlapped each other, so the upturn was obvious. When the deviation angle was greater than 30°, the pressure derivative curve characteristics were similar to that of horizontal wells and there was a vertical radial flow section, otherwise it was similar to that of vertical wells. The analytical solution was obtained by this model, and the parameter interpretation result was more accurate. Therefore, it can provide a theoretical guidance for developing low permeability reservoirs with inclined wells.

Multi-stage fracturing horizontal well interference test model and its application

LI Jiqing, LIU Yuewu, HUANG Can, GAO Dapeng

2018, Vol.30(6): 138–144 Abstract ( 587 ) PDF (2363 KB) ( 734 )

doi: https://doi.org/10.12108/yxyqc.20180617

After the large-scale development of horizontal wells and well networks in shale gas fields, the problem of "fast pressure drop and premature gas well abandonment" caused by inter-well interference has become increasingly serious. It is urgent to understand the transient pressure of multi-stage fracturing horizontal wells under interference from adjacent wells and seepage characteristics. For this purpose, the shale reservoirs after multi-stage fracturing reformation of horizontal wells were firstly divided into three areas:fracturing fractures, SRVs and unmodified substrates. Then multi-zone coupled seepage model was established according to the characteristics of the pores in each region and the flow mechanism, and the model was numerically solved by using the PEBI grid and finite volume method. Through numerical simulation, the influences of factors such as connected permeability and agitation on the test results and pressure field distribution characteristics of interference wells were analyzed. Taking JY7-1 HF well and JY7-2 HF well in Jiaoyan 7 well group as examples, the average permeability of the connecting section between the two wells was 18.5 mD, which was calculated by interference test pressure fitting method, showing good connectivity. It is recommended that the gas production should be controlled in the later production process, while avoiding frequent replacement of working systems in adjacent wells. In the future, well pattern deployment should be based on the design productivity of a single well. The fracturing scale should be controlled for the interval close to the horizontal section of the adjacent wells, and the interference well test should be conducted in due course.

Refracturing selection evaluation model for shale gas wells and its application

CUI Jing, GAO Dongwei, BI Wentao, LIAO Rugang

2018, Vol.30(6): 145–150 Abstract ( 275 ) PDF (2133 KB) ( 572 )

doi: https://doi.org/10.12108/yxyqc.20180618

In order to solve the problem of refracturing well selection in shale gas wells, the evaluation indexes such as the porous elastic stress steering coefficient, unit pressure drop yield, pressure coefficient, gas reservoir quality index and normalized pseudo-production decline rate were introduced for geological features of shale gas wells such as reservoir fault development, curvature and fracture distribution. The evaluation model of refracturing well selection for shale gas wells was established, and the candidate wells for refracturing were selected. At the same time, the technology of temporary plugging diverting technology in refracturing wells was clarified, and the design parameters of the refracturing process were optimized. This model was applied to the refracturing of Fuling shale gas well, and the optimized candidate wells can be retrofit. The daily output was increased by 5-6 times in the early stage of operation, which provided a reference for the long-term and efficient development of Fuling shale gas field.

Rock breaking mechanism of CO₂ and fracturing technology

DING Yong, MA Xinxing, YE Liang, XIAO Yuanxiang, ZHANG Yanming, GU Yonghong, MA Chaoxing

2018, Vol.30(6): 151–159 Abstract ( 279 ) PDF (5192 KB) ( 660 )

doi: https://doi.org/10.12108/yxyqc.20180619

In order to make clear the change rule of effective stress during the injection processes with different media and reveal the mechanical mechanism of low break down pressure, long penetrate distance and high fracture distribution density during super-critical CO2 fracturing, based on linear elastic porous medium model and linear decomposition of anisotropic stress on wellbore plane, pressurization rate was introduced to carry out correction of pore pressure and additional circumferential stress. In view of the characteristics of tight gas reservoir in Changqing gas field, with the dual advantages of CO2 rock breaking, pressurizing and slick water volume fracturing, geological reserve volume difference method of gas reservoir was improved to optimizing the CO2 injection quantity. According to the monitoring data of down hole pressure gauge, the dynamic filtration loss equilibrium point was analyzed, and the CO2 construction displacement was obtained. Thanks to anti-freeze isolating liquid, a single fracturing unit operation process was formed. Finally, CO2 volume fracturing technology was formed. The result shows that fracture initiation pressure dropped by 69.2% in the case of liquid CO2 and 75.5% in the case of super-critical CO2. Pilot tests were carried out on six wells in eastern Ordos Basin, 100% cleanup with no nitrogen lift, and the average single layer initial gas rate of subject wells is 75 900 m3/d, which indicates that CO2 fracturing techniques is expected to be a new stimulation method for Changqing gas field.

Optimization and application of deep gas well fracturing in Pingqiao block of Fuling shale gas field

ZHANG Chi

2018, Vol.30(6): 160–168 Abstract ( 285 ) PDF (2814 KB) ( 446 )

doi: https://doi.org/10.12108/yxyqc.20180620

The main layer of the shale in Pingqiao block of Fuling shale gas field has a depth of 3 900-4 100 m, which is located in the strong compressive stress area and has large formation dip, so the effect of formation fracturing is limited. The optimization of deep fracturing technology was studied by combining experimental simulation with field test. The results show that optimizing deep fracturing technology mainly includes the following methods: (1)Optimizing the distance of stages between 45 m and 50 m; (2)Using directional three-cluster perfora-tion can avoid the problem of deep fracture extending along the bedding, but also can ensure that the fracture has a certain degree of complexity; (3)Rapidly increasing the construction displacement of pre-glue fluid and increasing the construction displacement step by step in the stage of drag-reducing water and sand-carrying, which is beneficial to increase the complexity of the fractures after forming a certain width of main fracture in the initial stage; (4)The single-stage construction scale should be controlled at 1 900-2 000 m3. Compared with the conventional fracturing process, the net pressure in fracture increased by 12.5%, the average sand-fluid ratio increased by 75.56%, and the average single-stage gas production increased by 114.90%. The optimized process has broad application prospects.