Lithologic Reservoirs

Chang 3 reservoir of Yanchang Formation in Ordos Basin is similar to other reservoirs, but the reserves are the least. The data of cores, well logging, mud logging, oil testing and test mining in Xiasiwan Oilfield were applied to study the development characteristics and controlling factors of hydrocarbon accumulation of Chang 3 reservoir. The results show that the structure of Chang 3 reservoir in Xiasiwan Oilfield is relatively gentle and develops a EW-trending nose-shape structure. It belongs to delta plain subfacies, and its microfacies include branch channel, onshore natural dike, crevasse fan and marsh. Sand body is mostly developed in the branch channel microfacies. Reservoir lithology is dominated by fine-grained feldspathic sandstones, and the main pore type is intergranular pores. The average porosity is 12.4%, and the average permeability is 1.28 mD, with lowporosity and low-permeability. The reservoir is mainly controlled by lithology, followed by structural factors, which belongs to structural-lithologic reservoirs. The research results have a guiding role for oil and gas exploration in Chang 3 reservoir.

Carbonate cements and its effect on reservoir property of shallow marine sandstones of Zhuhai Formation in Panyu low-uplift,Pearl River Mouth Basin

DU Guichao, SU Long, CHEN Guojun, ZHANG Gongcheng, DING Chao, CAO Qing, LU Yuexin

2019, Vol.31(3): 10–19 Abstract ( 325 ) PDF (6741 KB) ( 270 )

doi: https://doi.org/10.12108/yxyqc.20190302

Based on a series of testing method of porosity & permeability measurements, mercury porosimetry measurements, thin section analyses, SEM observations and X-ray diffraction (XRD) analysis, diagenetic features and reservoir property of marine sandstones acquired from Zhuhai Formation in Panyu low-uplift of Pearl River Mouth Basin were analyzed. The results show that three stages of carbonate cements were identified in the studied reservoir sandstones, which was present by calcite and ferro-dolomite in syn-diagenesis, calcite, ferrodolomite and siderite in eodiagenesis, and a small amount of calcite and ferro-dolomite in A stage of eodiagenesis. Early calcite and ferro-dolomite precipitated basally within pore spaces formed supersaturated pore fluid in alkaline environment early in diagenetic history. The second stage of carbonate cements were characterized by porous cementation, and their sources include dissolution of bio-clasts, hydration of Aluminum silicate minerals, and residual pore fluid. In A1 stage of meso-diagenesis, diagenetic environment has been transformed into alkaline when acid fluid was exhausted. The third stage of carbonate cements precipitated when abundant Ca2+, Mn2+, Fe2+ and Mg2+ were dissolved and entered into pore fluid in relatively deeper burial depth, higher temperature and pressure. Carbonate cement is one of the most important factors that caused great loss of reservoir property in the studied reservoir sandstones, showing that the higher content of carbonate cements occurred, the poorer of the reservoir property is. Most obviously, early carbonate cements occurred basally and highly reduced reservoir property. The second stage of carbonate cements generally were featured by porous cementation and blocked the pore spaces. Late carbonate cements generally have a low content, but occurred as replacements of detrital grains or pore fillings in intergranular pores and dissolution pores, which caused further densification of reservoir sandstones. The results can provide a basis for the prediction of favorable zones and the evaluation of exploration targets in this area.

Characteristics of fluid inclusions and hydrocarbon accumulation stages of Yanchang Formation in Fengfuchuan area,Ordos Basin

TANG Jianyun, ZHANG Gang, SHI Zheng, ZHANG Xing, CHEN Yubao

2019, Vol.31(3): 20–26 Abstract ( 292 ) PDF (3003 KB) ( 346 )

doi: https://doi.org/10.12108/yxyqc.20190303

In order to determine hydrocarbon accumulation period and characteristics of oil-gas fluid inclusion in Chang 2 and Chang 6 reservoir in Fengfuchuan area of Ordos Basin, fluorescence microscope identification and hot and cold temperature experimental analysis were carried out, and the homogenization temperature of inclusions and burial history and thermal evolution history were applied to determine the oil and gas filling time of the target zone.The results show that:(1) fluid inclusions in the study area mainly consist of saline inclusions and liquid hydrocarbon inclusions; (2) the homogenization temperatures of fluid inclusions in Chang 6 and Chang 2 reservoir are 100-120℃ and 90-110℃, respectively, and the stratum was in diagenetic A stage when fluid inclusions were captured, with salinity less than 10.5‰, which belonged to moderate salinity; (3) both Chang 2 and Chang 6 were filled with oil and gas in the first stage, which was Early cretaceous. The oil and gas filling time of Chang 2 is 115-100 Ma, and that of Chang 6 is 120-105 Ma. The research results confirm that Yanchang Formation in Fengfuchuan area is a continuous filling reservoir.

Organic pore development characteristics of Longmaxi and Niutitang shales in the periphery of Chongqing

WANG Pengfei, JIANG Zhenxue, YANG Caihong, JIN Can, LYU Peng, WANG Haihua

2019, Vol.31(3): 27–36 Abstract ( 297 ) PDF (12139 KB) ( 419 )

doi: https://doi.org/10.12108/yxyqc.20190304

In the exploration and development process of shale gas in Niutitang Formation, there are problems such as low gas production and short duration. By comparing the Lower Silurian Longmaxi shale in southeastern Chongqing with the Lower Cambrian Niutitang shale in northeastern Chongqing, the pore reservoir capacity and evolution characteristics of the two sets of shale were analyzed. The results show that there are significant differences in organic pore development characteristics of the Longmaxi shale and the Niutitang shale. The organic pores inside solid kerogen in the Longmaxi shale have a small number, small pore size and poor connectivity, but the amount and size of organic pores in pyrobitumen are large, and the connectivity is good. The solid kerogen and pyrobitumen in the Niutitang shale do not develop organic pores. The degree of reservoir thermal evolution has a direct control effect on the development of organic pores in shale. The Longmaxi shale is relatively weak in thermal evolution as palaeo-buried depth is shallower than the Niutitang shale. The appropriate degree of thermal evolution preserves a large amount of organic pores in the pyrobitumen of the Longmaxi shale, but the solid kerogen has a relatively long evolution time and the number of organic pores decreased. The palaeo-buried depth of the Niuzhitang shale in northeastern Chongqing is too large, and reservoir reached the metamorphic period due to excessive evolution, resulting in the absence of organic pores in the solid kerogen and pyrobitumen. For the efficient exploration and development of shale gas in the Niutitang Formation, a shale distribution area with moderate thermal evolution should be sought.

Sedimentary characteristics of near-source braided river delta of the upper third member of Shahejie Formation in Kenli A oilfield

ZHAO Hanqing, WEN Huiyun, MU Pengfei, LI Chao, WU Qiongyuan

2019, Vol.31(3): 37–44 Abstract ( 324 ) PDF (5660 KB) ( 499 )

doi: https://doi.org/10.12108/yxyqc.20190305

In order to reveal the sedimentary characteristics and distribution regularity of the upper third member of Paleogene Shahejie Formation in Laizhou Bay Sag, Bohai Bay Basin, the sedimentary facies types and distribution characteristics under sequence framework were summarized by using core, grain size, casting thin section, mud logging and seismic data. The results show that a typical near-source braided river delta sedimentary system developed in Kenli A oilfield. Three kinds of subfacies were recognized, including braided river delta plain, braided river delta front and pro-braided river delta, which can be further divided into the following six sedimentary microfacies:braided channel, alluvial plain, underwater distributary channel, underwater distributary interchannel, mouth bar and sheet sand. By using sequence stratigraphy, the upper member of Sha 3 was divided into a set of third-order sequence. The lowstand systems tract (LST) was dominated by thick sandstone in underwater distributary channel, while the transgressive systems tract (TST) and highstand systems tract (HST) were dominated by thin sandstone. Sandstone thickness and distribution scale in different systems tracts were controlled by lake level fluctuation and sediment supply rate. This rule can provide a reference for the evaluation of sandstone reservoir in the gentle-slope zone of faulted lacustrine basin.

Gas and water distribution and its controlling factors of Xiashihezi Formation in J58 well area,Hangjinqi area

DUAN Zhiyou, LI Xianqing, CHEN Chunfang, MA Liyuan, LUO Yuan

2019, Vol.31(3): 45–54 Abstract ( 301 ) PDF (4991 KB) ( 380 )

doi: https://doi.org/10.12108/yxyqc.20190306

Xiashihezi Formation in J58 well area is a key section of tight sandstone gas exploration and development in Hangjinqi area. At present, the distribution of gas and water and its influencing factors are not clearly understood, which greatly restricts the effective development of natural gas. Based on the study of geological characteristics of the study area, through comprehensive analysis of logging data, gas test data and formation water chemistry of more than 30 wells in this area, the distribution law of gas and water and the main controlling factors in J58 well area were defined. The results show that the salinity of formation water in this area is 24 176-76 917 mg/L, and the formation water types are all CaCl2, which reflects that the formation water is well sealed and conducive to the accumulation and preservation of natural gas. Vertically, gas and water differentiation is not obvious, the continuity of gas and water layer is poor and most of them are coexisting gas and water zone, and the gas reservoir of He 1 member is more developed. In the plane, gas layers are concentrated in the channel sand bodies, while water layers are mainly located at the edge of sand bodies. The distribution of gas and water is mainly controlled by hydrocarbon generating intensity, sedimentary facies, effective sand body thickness and pebbly sandstone thickness. Gas reservoirs are mainly distributed in areas where hydrocarbon generation intensity is greater than 15×108 m3/km2. The closer the distance between reservoirs and hydrocarbon source rocks, the more developed the gas reservoirs are. Sedimentary facies, effective sand body thickness and pebbly sandstone thickness further control gas production and the distribution range of gas and water layers. The results of this study have a guiding role in determining the favorable target areas for natural gas in the study area.

Characteristics of microscopic pore structures and main controlling factors of Wufeng-Longmaxi Formation shale in southern Sichuan Basin

ZHENG Shanshan, LIU Luofu, WANG Yang, LUO Zehua, WANG Ximeng, SHENG Yue, XU Tong, WANG Bohan

2019, Vol.31(3): 55–65 Abstract ( 326 ) PDF (5295 KB) ( 490 )

doi: https://doi.org/10.12108/yxyqc.20190307

To study the pore structure characteristics and main controlling factors of Wufeng-Longmaxi Formation shale in southern Sichuan Basin, the organic geochemistry, X-ray diffraction analysis of whole rock mineral content and clay mineral content, scanning electron microscopy of argon ion polishing, high pressure mercury injection test and gas (CO2 and N2) isothermal adsorption experiments were carried out on shale samples from nine coring wells. The results show that:(1) The average TOC mass fraction of shale is 2.42%, the average vitrinite reflectance (Ro) is 2.83%, and the organic matter is in over-mature stage. The clay minerals of shale are mainly composed of mixed-layer minerals of illite and montmorillonite, illite and chlorite, so it is in the late diagenetic stage. (2) The average porosity of shale is 2.49%, and pore size is mainly 2.6-39.8 nm, with bottle-shaped and slit holes of fine-necked ink. The mass volume of saturated absorbed gas is 0.0147-0.0322 cm3/g, and the specific surface area of total pores is 19.49-40.68 m2/g. Mesopores and macropores provide the main reservoir space for shale gas reservoir, while micropores contribute greatly to the pore surface area. (3) TOC content, degree of thermal evolution and clay mineral content all have a certain controlling effect on specific surface area of micropores and mesopores, the development degree of interlayer pore has an effect on the mesopore and macropore volume, and the content of brittle minerals is negatively correlated with the volume of micropore, mesopore and macropore. The study results have a guiding role in searching for high-quality reservoirs and shale gas enrichment areas in the southern Sichuan Basin.

Adsorption characteristics of Upper Paleozoic shale gas in ZhongmouWenxian block,South North China Basin

LI Pei, ZHANG Jinchuan, TANG Xuan, HUO Zhipeng, LI Zhen, LIU Junlan, LI Zhongming

2019, Vol.31(3): 66–75 Abstract ( 295 ) PDF (3252 KB) ( 426 )

doi: https://doi.org/10.12108/yxyqc.20190308

In order to study the characteristics of shale gas adsorption and its main controlling factors of Upper Paleozoic Shanxi-Taiyuan Formation in Zhongmou-Wenxian block of South North China Basin, a comprehensive prediction model of temperature-pressure adsorption was established based on the isothermal adsorption experiment of shale gas. The results show that:(1) Taiyuan shale with high Langmuir volume has stronger adsorption capacity compared with Shanxi shale, but Shanxi shale with higher Langmuir pressure is more conducive to shale gas desorption. (2) The buried depth and water content of shale are positively and negatively correlated with adsorbed gas content, respectively, which may be mainly controlled by temperature and pressure conditions and mass transfer in phase change. (3) The increasing temperature can lead to the decrease of adsorption capacity and Langmuir volume attenuation coefficient, reflecting temperature has a significant effect on the adsorption capacity of shale. However, the negative effect of temperature becomes weaker and weaker under deep burial conditions (>3 731 m), and the higher Langmuir pressure under deep burial condition makes the high pressure stage conducive to methane desorption in the depressurization process. Therefore, the deep shale gas (>3 500 m) in the northern part of the study area still has good exploitation potential. The research results have certain guiding significance for deep shale gas exploration.

EXPLORATION TECHNOLOGY

Fracture identification for tight reservoirs by conventional and imaging logging: a case study of Permian Lucaogou Formation in Jimsar Sag,Junggar Basin

LIU Dongdong, YANG Dongxu, ZHANG Ziya, ZHANG Chen, LUO Qun, PAN Zhankun, HUANG Zhixin

2019, Vol.31(3): 76–85 Abstract ( 348 ) PDF (5099 KB) ( 616 )

doi: https://doi.org/10.12108/yxyqc.20190309

Well logging is widely used in identifying fractures in conventional reservoirs. However, this approach is rarely used in analyzing fractures in tight reservoirs. The fractures in the tight reservoir of Lucaogou Formation in Jimusar Sag were identified and quantitatively characterized by conventional logging and imaging logging methods, the response characteristics of conventional logging to fractures were systematically summarized, the fracture genesis were analyzed by using imaging logging data, and the development of the upper and lower sweet spots were compared. The results show that the conventional porosity logging is most applicable for identifying natural fractures in tight reservoirs, resistivity logging is also usable, and lithologic logging is poorly effective. In fracture developed zones, the natural gamma value is more than 70 API, the shallow resistivity is generally less than 80 Ω·m, the volume density of rock is less than 2.43 g/cm3, the neutron porosity is more than 28%, and the acoustic acoustic moveout is more than 246 μs/m. The imaging logging has different response characteristics to different fillers. According to the different imaging logging characteristics, the block, strip, linear and other imaging logging models were proposed. The natural fractures in the upper and lower sweet spots have similar dip direction, mechanical origin, and total linear density, though the fractures in the lower sweet spot display relatively larger width and develop more concentrated. These results are of great significance for the identification and evaluation of natural fractures in tight reservoirs.

Residual moveout correction of prestack seismic gathers based on SBL and DTW

SHI Zhanzhan, XIA Yanqing, ZHOU Huailai, WANG Yuanjun

2019, Vol.31(3): 86–94 Abstract ( 339 ) PDF (4822 KB) ( 474 )

doi: https://doi.org/10.12108/yxyqc.20190310

The residual moveout correction method based on dynamic time warping is faced with two problems:the dynamic time warping algorithm is sensitive to noise, and it is difficult to calculate the warping path accurately; the algorithm adopts a point-by-point moving method, which corrects residual moveout of seismic trace directly, and may cause seismic waveform distortion. Aiming at these problems, a residual moveout correction method of prestack gather was proposed based on sparse Bayesian learning (SBL) and dynamic time warping (DTW). The implementation steps are as follows:sparse representation of seismic gathers was realized via sparse Bayesian learning, and then the residual moveout correction of the sparse representation results was conducted by dynamic time warping, and the seismic records were reconstructed after processing. This method utilizes sparse Bayesian learning with good noise robustness and few local minimums. The global optimal solution is also the sparsest one. After sparse decomposition, the unit impulse response of subsurface was obtained, and the wavelet effect was eliminated, and then the distortion of waveform caused by using dynamic time directly can be avoided. The highlight of this method is that high fidelity residual moveout correction and random noise suppression are simultaneously achieved. Numerical simulation and actual data processing results show that the proposed method has a good application effect.

Well logging evaluation methods of key parameters for shale gas reservoir in Dingshan block,Sichuan Basin

YAN Wei, LIU Shuai, FENG Minggang, ZHANG Chong, FAN Shuping

2019, Vol.31(3): 95–104 Abstract ( 313 ) PDF (3375 KB) ( 402 )

doi: https://doi.org/10.12108/yxyqc.20190311

Dingshan block is another shale gas source of 100 billion square meters. However, compared with other shale gas blocks, the logging response of the reservoir in Dingshan block is less correlated with the reservoir parameters, and because the formation pressure changes greatly, it is easy to cause the wellbore to collapse, resulting in that the parameter evaluation system dominated by density curve applied in other bolcks is challenged in this block. This paper analyzed the relationship between log response characteristics and core experimental data of key wells in Dingshan block to determine their correlation, and established evaluation models of organic carbon content, porosity, minerals content and water saturation by combining the empirical statistics and apparent skeletal density method. Compared with core experimental parameters, the relative error of the parameters calculated by the model based on uranium content curve is less than 8%, with high precision. So the model is significantly better than the model dominated by density curve, it can meet the needs of actual reservoir evaluation and the calculation requirements of reserves, and also provide corresponding support for the exploration and development of shale gas reservoir in Dingshan block.

Seismic response characteristics and thickness prediction of thin interbedded igneous rocks

LIU Gongli, HAN Zijun, DUAN Xinyi, ZHEN Zongyu

2019, Vol.31(3): 105–112 Abstract ( 232 ) PDF (5374 KB) ( 462 )

doi: https://doi.org/10.12108/yxyqc.20190312

Igneous rocks are widely developed in Paleogene in B oilfield of Bohai Sea area. The igneous rocks dominated by eruption mainly exist in the form of thin interbeds, and their lateral thickness varies largely. It is very important to accurately describe the thickness distribution of igneous rocks for well location deployment and reserves evaluation. Based on the known thickness distribution and combination law of igneous rocks in drilled wells, it is considered that overflow igneous rocks in the form of thin interbeds have a great influence on oil field exploration and development. The influencing factors such as combination, total thickness and igneous rock ratio were systematically studied, which lead to different seismic response characteristics of thin interbedded igneous rocks. Based on real data, different analysis models were established to demonstrate the influences of the three factors. It is considered that igneous rock ratio is the main controlling factor affecting the amplitude of seismic response. Relationship between igneous rock ratios and amplitude was established by using actual wavelet forward modeling, and the thickness of thin-interbed igneous rocks was predicted using constrained sparse pulse inversion. The result shows that the predicted thickness is in good agreement with actual drilling thickness, so this method is helpful to quantitatively study the influence of igneous rocks on underlying structures. The research results have good guiding significance for further exploration and reserves evaluation.

OIL AND GAS FIELD DEVELOPMENT

Influence of pore throat structure on reservoir damage with CO₂ flooding

TANG Meirong, ZHANG Tongwu, BAI Xiaohu, WANG Xuanyi, LI Chuan

2019, Vol.31(3): 113–119 Abstract ( 254 ) PDF (3104 KB) ( 298 )

doi: https://doi.org/10.12108/yxyqc.20190313

In the process of enhancing oil recovery by CO2 flooding, the interaction of CO2 with crude oil and matrix minerals will damage the pore throat structure of reservoir. In order to reveal the influence of pore throat structure on reservoir damage during CO2 flooding, nuclear magnetic resonance (NMR) combined with high pressure mercury injection and scanning electron microscopy was used to determine the plugging degree of pore throat in core samples through laboratory physical simulation experiments, and the damage degree of core samples with different pore throat structures during CO2 flooding was evaluated, to clarify the reservoir damage mechanism. The experimental results show that asphaltene deposition and acidification produced during CO2 flooding have little effect on reservoir porosity, and the porosity of core samples decreased by about 1%. While the damage to permeability is greater, and the permeability of core with type Ⅲ pore structure decreased by 20.55%. The lower the permeability and the worse the pore throat structure, the greater the damage to permeability. The plugging degree of pore throat is positively correlated with pore throat structure parameters. The worse the pore throat structure is, the lower the median radius is, the easier the pore throat plugging will occur. The rate of pore throat plugging in type I pore structure cores is low, and the degree of pore throat plugging in type Ⅲ pore structure cores is obviously increased, up to 34.32%. The results can provide a basis for efficient application of CO2 flooding in the field.

Physical properties variation of WXS reservoir after long-term water flooding

XIONG Shan, WANG Xuesheng, ZHANG Sui, ZHAO Tao, PANG Fei, GAO Lei

2019, Vol.31(3): 120–129 Abstract ( 264 ) PDF (4626 KB) ( 387 )

doi: https://doi.org/10.12108/yxyqc.20190314

After decades of waterflooding, WXS reservoir of Tuha Oilfield has entered a high water cut stage. The mineral composition and clay composition, and pore structure of the reservoir have been changed by longterm washing and soaking of the injected water, which causes the change of reservoir sensitivity. On the basis of analyzing the changes of rock mineral composition, clay composition, permeability and pore structure before and after long-term water injection by using test methods of X-ray diffraction, full rock quantitative analysis, core mercury intrusion, scanning electron microscope (SEM), reservoir sensitivity evaluation experiments were carried out for the cores of water-flooded layer and the cores of oil layer respectively. The results show that longterm water flooding can easily cause the decrease of clay mineral content and enhance the reservoir heterogeneity. After long-term water flooding, the reservoir sensitivity varies in different degrees, and the variation range varies with the sensitivity types and the layers. The later stage of water injection and reservoir reconstruction should be adjusted according to the different reservoir sensitivity of different layers to improve the development effect of oilfields.

Economic limit water cut of single well in offshore waterflooding oilfield

ZHOU Yanbin, HE Yifan, ZHANG Wei, ZHANG Jilei, YANG Lei

2019, Vol.31(3): 130–134 Abstract ( 298 ) PDF (1289 KB) ( 379 )

doi: https://doi.org/10.12108/yxyqc.20190315

Economic limit water cut has important economic significance for the development of oilfields with water injection. The industry standard selected 98% as the economic limit water cut of single well, without considering economic factors, which is obviously unreasonable. In order to reasonably determine the economic limit water cut of single well under different economic conditions and evaluate whether the production of single well has economic benefits, guided by the principle of input-output balance, a calculation model of economic limit water cut of single well in offshore waterflooding oilfield was derived for the first time based on the economic parameters such as oil price, actual output, cost and tax. Taking Bohai Q oilfield as an example, the economic limit water cut of single well was calculated under different oil prices and oil production rates, and the corresponding chart was drawn to evaluate whether the production of oil wells has economic benefits. The results show that when the cost is fixed, oil price and oil recovery rate have a great influence on the economic limit water cut, and the economic limit water cut increases with the increase of oil price and oil recovery rate. For offshore waterflooding oilfields with high oil recovery rate, the economic limit water cut is as high as 99.11% at high oil price ($100/bbl, 1 bbl=0.159 m3), which is much higher than 98% of the economic limit water cut value stipulated by the current industry standard. It prolongs the benefit production of oil wells in high water cut period, greatly improves the economic benefit of single well, and has important guiding significance for the production strategy of offshore waterflooding oilfields.

Sensitivity experiment of shale gas reservoir of Chang 7 reservoir in Xiasiwan oilfield

XUE Dan, ZHANG Sui'an, WU Xinmin, LI Xuhang, DU Junjun, LU Chengang

2019, Vol.31(3): 135–144 Abstract ( 301 ) PDF (2963 KB) ( 398 )

doi: https://doi.org/10.12108/yxyqc.20190316

There are many microcracks and lamellations developed in Chang 7 shale gas reservoir, and matrix shale and fractured shale coexist, so the reservoirs are easily damaged during the development process. Sensitivity evaluation experiment is one of the important means to explore reservoir damage, however, the current experiment mainly focuses on the matrix shale. Considering that shale reservoirs often need fracturing before the shale gas can be produced, and the damage mechanism of matrix shale is different from that of fractured shale, the core flow experiment of fractured shale and the pressure pulse attenuation experiment of matrix shale were combined to study the sensitive damage mechanism of Chang 7 shale gas reservoir. The results show that the shale reservoir has the characteristics of strong stress sensitivity, medium alkali sensitivity, moderately weak water sensitivity, and moderately weak velocity sensitivity. It is found that the damage degree of fractured shale is higher than that of matrix shale in all kinds of experiments except stress sensitivity evaluation experiment. The main reason is that the presence of fractures increases the area of interaction between external fluid and formation, thus causing greater damage. Overall, the stress sensitivity of matrix shale is stronger than that of micro-fractured shale, but slightly lower than that of fractured shale. The research results can provide a basis for efficient development of shale gas.

PETROLEUM ENGINEERING

Shut-in and flow-back pattern of fractured shale gas wells

DU Yang, LEI Wei, LI Li, ZHAO Zhejun, NI Jie

2019, Vol.31(3): 145–151 Abstract ( 298 ) PDF (3099 KB) ( 500 )

doi: https://doi.org/10.12108/yxyqc.20190317

Horizontal well staged fracturing is the main technical mean of shale gas reservoir reformation, the large fracturing fluid was injected into the formation but the flow-back rate was relatively low. The pros and cons are still unclear about the retention fracturing fluid in the formation. In order to solve this problem, cores of Longmaxi Formation from well YY1 in Xindianzi structure of Yongchuan were selected to carry out imbibition experiment with slick-water, and the variation rules of core physical properties, pore structure characteristics and micro-structure were compared. The results show that after fracturing fluid imbibition, the average porosity and permeability increased by 50% and 25% respectively, while gas adsorption capacity and specific surface area decreased by 35% and 40% respectively. Micro fissures were created along the bedding direction after imbibition test, and with the continuous infiltration, the fissures expanded and extended, gradually communicated the fracture network, and increased the infiltration area of liquid. Through field test of well YY1 HF, it is found that after 30 days of shut-in test under the production rate of 60 000 m3/d, the production of liquid is greatly reduced, and the production of gas wells is stable. Therefore, post-frac shut-in is beneficial to improve reservoir physical properties and increase seepage channels, and gradual enlargement flow-back strategy is better for gas recovery.

Influence of bedding on compressional wave characteristics of shales

LI Xiansheng, LIU Xiangjun, XIONG Jian, LI Wei, LIANG Lixi

2019, Vol.31(3): 152–160 Abstract ( 266 ) PDF (3882 KB) ( 416 )

doi: https://doi.org/10.12108/yxyqc.20190318

Studying the acoustic characteristics of layered shales contributes to applying acoustic logging to guide drilling safely. The shale samples were collected from the Lower Silurian Longmaxi Formation in Changning area of Sichuan Basin, and drilled into cores along different orientation relative to the bedding plane. Based on multi-frequency ultrasonic wave testing system, acoustic wave experiments of shale samples were carried out and the influences of bedding angle on acoustic wave velocity, attenuation coefficient, time domain and frequency domain were analyzed. Numerical simulation experiments were carried out to analyze the influences of bedding density on wave velocity and attenuation in parallel and vertical core end faces. The results show that the interval transit time and the attenuation coefficient increase linearly with the increase of bedding angle. Frequency dispersion phenomenon exists, which shows that the acoustic velocity varies with the testing frequency. Acoustic velocity is negatively correlated with bedding density, and bedding angle has no effect on the dominant frequency of shale acoustic waves. The results provide a reference for the drilling and fracturing engineering of shale gas wells.