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Sweet spot evaluation is of great significance for efficient exploration and development of shale gas reservoirs. Taking the shale reservoir in Ordovician Wulalike Formation on the western margin of the Ordos Basin as the research object, eight experiments including rock section analysis, X-ray diffraction, SEM scanning electron microscopy, low-temperature nitrogen adsorption, isothermal adsorption, total organic carbon (TOC) content test, organic matter vitrinite reflectance (Ro) test and triaxial rock mechanics test were carried out in this study. It is found that the rock type in the target area is gray brown mud shale, with the pore size in the ranges of 2-4 nm and 35-61 nm, and intergranular pores, clay mineral interlayer pores and intragranular pores are developed. The TOC content is 1.01%, the average Ro value is 1.75%, and the brittleness index is 47.8%. By analyzing the influence of different factors on the selection and evaluation of shale reservoir sweet spots, it is concluded that the content of siliceous minerals, clay minerals, pore specific surface area, TOC content and Ro value play a decisive role on the adsorption perfor-mance of the reservoir, the pore size and the number of pore types control the reservoir property, the content of brittle minerals and rock mechanics parameters affect the compressibility of the reservoir. According to the two indexes of adsorption property and reservoir property evaluated by geological sweet spots and the compressibility index of engineering sweet spots, the parameter indexes corresponding to different characteristics are finely classified, and a classification and evaluation scheme of geological sweet spots and compressibility sweet spots of the marine shale gas reservoir in Ordovician Wulalike Formation in the Ordos Basin is preliminarily established. The results show that all characteristic para-meters in the target area meet the grade Ⅱ standard. It could be a sweet spot for shale gas development.

Permian Wujiaping Formation in Hongxing area of eastern Sichuan is rich in high-quality shale, and multiple wells have achieved high productivity of industrial gas. It is an important replacement block for the natural gas production capacity of the Jianghan Oilfield. However, due to the complex structure and lithology, deep burial depth of the target layer, and large fluctuations in the attitude of thin reservoirs, complex situations such as well leakage and collapse occuring frequently, low mechanical drilling speed, long drilling cycles, and difficulty in ensuring the drilling rate of high-quality reservoirs seriously restrict the benefit development. Based on the summary of previous data, the drilling difficulties were analyzed, the optimal design of drilling engineering was carried out, and some key rock breaking tools were selected to optimize the density and sealing performance of drilling fluid. The "three opening" wellbore structure with three different diameters, "irregular tooth PDC and mixed drill bits + high torque equal wall thickness screw + reinforced parameter drilling", simple pressure control by a rotary control head, and low density and strong sealing drilling fluid technology for "both leakage and collapse treatment" were formed. We have established a geological engineering integrated guidance technology based on "vertical depth prediction, segmented slope control, and five charts and one table", and proposed the direction for further improvement. The on-site application shows that: (1) the "three opening" wellbore structure with three different diameters meets the safety drilling requirements in Hongxing area, laying the foundation for drilling speed increase. The parameter drilling was enhanced by high-performance PDC, and the mechanical drilling speed of each opening is significantly improved. The drilling speed of the third opening section in the Permian formation increased by 15%, and the horizontal section increased by 22%; (2) The density reduction and nano sealing drilling fluid technology effectively reduced the number and time of complex treatments, and the time for complex treatments was reduced by 20.5% compared to the early implementation of wells; (3) The penetration rate of high-quality reservoirs significantly increased to 93.27%, an increase of 19.85% compared to the previous period.

Marine shale gas, represented by the shale gas from Wufeng-Longmaxi formations in southern China, is the main field for shale gas exploration and development in China. In recent years, marine shale gas exploration and development have been constantly facing new problems and challenges. Expanding new fields of shale gas resources and increasing shale gas production are still top priorities. The distribution characteristics, resource potential, and favorable area prediction of shale gas in typical marine formations in China are sorted out, with the results as follows. The geological and recoverable resources of shale gas in Wufeng-Longmaxi formations in Sichuan Basin and its peripheral regions are (17.50-33.19)×1012 m3 and (3.50-6.14)×1012 m3, respectively, with deep shale gas resources accounting for over 50%, mainly distributed in the high and steep structural belt in eastern Sichuan and in the low steep structural belt in southern Sichuan. The geological and recoverable resources of shale gas in the Permian Wujiaping Formation are (8.7-24.6)×1012 m3 and (1.3-3.7)×1012 m3, respectively, with exploration potential in areas such as Kaijiang-Liangping, Longjuba, Jiannan, and Sanxing in eastern Sichuan. The geological and recoverable resources of shale gas in the Qiongzhusi Formation are (5.69-12.71)×1012 m3 and (0.89-1.06) ×1012 m3, respectively, with favorable areas mainly distributed in areas such as Jingyan-Jianwei-Weiyuan-Ziyang in southwestern Sichuan, Nanjiang in northern Sichuan, and Yichang in the middle Yangtze region. The ancient marine formations such as the Doushantuo Formation, Hongshuizhuang Formation, and Xiamaling Formation have certain potential of shale gas resources, which are potential continuation of shale gas resources. The favorable areas for shale gas in the Doushantuo Formation are mainly distributed in western Hunan and Hubei and southeast Chongqing, while the favorable areas for shale gas in the Hongshuizhuang Formation are mainly distributed in the Chengde-Kuancheng area of Hebei. The favorable areas for shale gas in the Xiamaling Formation are mainly distributed in the areas of Zhuozhou in Hebei, Fangshan, Mentougou, Changping in Beijing, and Lanqi-yingzi. Based on this, three suggestions are further proposed for the future exploration direction of marine shale gas: the first is to focus on deep to ultra-deep and normal pressure shale gas, move towards new layers, and expand the field of shale gas exploration; the second is to deepen and enrich the exploration theory of deep to ultra-deep shale gas, normal pressure shale gas, and shale gas of new layer in the new area; the third is to focus on the improvement and innovation of deep to ultra-deep shale gas drilling and production technology and supporting equipment, and reduce the drilling and production costs of single wells of normal pressure shale gas.

The exploration and development theory and technology of marine shale gas with shallow burial depth of 3500 m in South China has become mature after more than 10 years of practice. In order to continuously promote the exploration and development of shale gas in China, based on the research results of many scholars, combined with production practice, the main characteristics of marine shale gas in China and the main theory and technology of exploration and development are further summarized. The results show that: (1) The basic characteristics of marine shale gas in southern China are marine deep-water shelf deposition, and organic-rich shale is distributed continuously in a large area; The organic matter is stored in situ after high thermal maturity gas generation, and the gas content of shale is affected by late tectonic activity; The reservoir space is dominated by nano-scale pores, and the reservoir is super-tight and ultra-low permeability, which has no natural productivity without well stimulation; Bedding and natural fracture affect the productivity of shale gas wells; The mechanical properties of shale rock determine the effect of horizontal wells. In the early stage of well production, the production rate is high and the decline is fast, while in the middle and late stage, the rate is low but the production cycle is long. (2) Based on the above characteristics, the theory of “sweet spot” and “sweet interval” of shale gas and the theory of effective development of artificial gas reservoir are established, that is, the sedimentary and tectonic interaction forms the “sweet area” or “sweet spot” of marine shale gas. Gas productivity is determined by geological and engineering factors, so the “sweet spot” must be found to develop. By constructing artificial gas reservoir through “making an artificial high permeability area, and reconstructing a seepage field”, the effective development of ultra-tight and low permeability shale gas reservoirs can be realized. It is the most effective technique for shale gas development to accurately create “transparent geological body” of reservoirs based on geology-engineering integrated evaluation technology and establish artificial gas reservoir through multi-stage fracturing technology. (3) The overpressure area in the southern Sichuan Basin is the “sweet area” for shale gas development. The “sweet interval” of the lower Silurian Longmaxi Formation with a thickness of 3–5 m and high brittle-rich organic matter is the optimal “golden target” for horizontal wells. (4) The development leapfrog from the first generation to the second generation has been realized by the key technology of multi-stage fracturing of horizontal wells. The EUR per well of Upper Ordovician Wufeng Formation and Longmaxi Formation in southern Sichuan has increased from 0.5 × 108 m3 in the initial stage to 1.0 × 108–1.2 × 108 m3 at present with a buried depth of shallower than 3500 m. (5) The effective area favorable for shale gas development in southern Sichuan is 2.0 × 104 km2, and it is estimated that the proven geological reserves of shale gas can reach 10 × 1012 m3. It is preliminarily predicted that the shale gas production in China will exceed 300 × 108 m3 in 2025 and reach 400 × 108 m3 in 2035.

Total organic carbon content (TOC) is the most important parameter to determine the quality of source rocks. In order to solve the problem of low accuracy in the application of the traditional ΔlogR method to marine shale gas reservoirs with complex depositional environments, taking the marine shale gas reservoirs of Group B in Area A of Guizhong Depression as the research object, based on the analysis of the causes of low resistance in the study area, the well diameter correction of the logging curve was performed according to the range of expansion, taking the B-group marine shale gas reservoir in the Guizhong Depression A as the study object. The Th/K data from natural gamma energy spectrum logs were also used to establish a multivariate fitting relationship with ΔlogR. An improved ΔlogR method based on well diameter correction and natural gamma energy spectrum logs was proposed. The results show that after the correction of the acoustic transit time curve, the influence of the logging data distortion caused by the diameter expansion of the well was reduced. At the same time, combined with natural gamma spectroscopy logging, it can adapt to the complex geological background and strong heterogeneity of the study area, greatly improve the prediction accuracy of the total organic carbon mass fraction, and has good generalization and applicability. This method can provide a reference for the evaluation of marine shale gas reservoirs from Group B in area A of Guizhong Depression. [ABSTRACT FROM AUTHOR]

The identification of high-quality marine shale gas reservoirs has always been a key task in the exploration and development stage. However, due to the serious nonlinear relationship between the logging curve response and high-quality reservoirs, the rapid identification of high-quality reservoirs has always been a problem of low accuracy. This study proposes a combination of the oversampling method and random forest algorithm to improve the identification accuracy of high-quality reservoirs based on logging data. The oversampling method is used to balance the number of samples of different types and the random forest algorithm is used to establish a high-precision and high-quality reservoir identification model. From the perspective of the prediction effect, the reservoir identification method that combines the oversampling method and the random forest algorithm has increased the accuracy of reservoir identification from the 44% seen in other machine learning algorithms to 78%, and the effect is significant. This research can improve the identifiability of high-quality marine shale gas reservoirs, guide the drilling of horizontal wells, and provide tangible help for the precise formulation of marine shale gas development plans.

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In this paper, shale gas cores from the Lower Silurian Longmaxi Formation in the Zhaotong National Shale Gas Demonstration Area were selected to study the hydration effect of different fluids on the fracture morphology inside the shale, the rock tensile strength and the Brazilian tensile failure mode. Fresh water and slick water were adopted for hydration pretreatments and the CT technique was used to compare the changes of the fabric in the shale. Then, Brazilian tensile tests were carried out to study the tensile strength and tensile failure modes of the shale specimen after hydration pretreatment. Finally, two horizontal wells in the study area were selected to perform pilot tests of hydration pretreatment in their fracturing operation sites. And the following research results were obtained. First, in the process of spontaneous imbibition, the hydration effect of fresh water is superior to that of slick water in promoting the fracture complexity of marine shale in the same hydration duration. Second, fresh water has greater surface tension and lower viscosity and its hydration effect can not only promote the propagation of original fractures but induce new micro-fractures or branches, while the hydration effect of slick water mainly promotes the propagation of original fractures. Third, due to hydration effect, marine shale is damaged and its tensile strength is reduced. After the hydration pretreatment by fresh water and slick water, the tensile strength of the shale specimens are reduced by 35.6% and 18.1%, respectively. Fourth, according to the propagation paths of main fractures, the Brazilian tensile failure modes of hydrated shale can be divided into four types (i.e., step shaped, dog-leg shaped, branching shaped and arc shaped) or their combinations, while the tensile failure mode of unhydrated shale is only a straight line. Fifth, hydration effect can effectively increase the complexity of the hydraulic fractures in marine shale, so if the conditions permit, it is recommended to inject a certain amount of fresh water at a high pumping rate within the limited pressure after perforation and to shut in the well until the hydraulic fracturing operation. And in order to reduce the difficulties of pumping the proppant during the hydraulic fracturing operation, a pumping strategy of “low proppant concentration, large volume of slurries” can be adopted to reach the expected proppant volume.

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Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The exploration and development of marine shale gas reservoirs in South China is challenged by complex geological and geographical conditions, such as strong transformation, post maturity, complex mountains and humanity. In this paper, the evaluations on shale gas sweet spots conducted in Zhaotong demonstration zone in the past six years and the construction of 500 million m3 shale gas productivity in Huangjinba region were discussed, and the results of shale gas reservoir evaluations in China and abroad were investigated. Accordingly, it is proposed that another two key indicators be taken into consideration in the evaluation on shale gas sweet spots in marine mountains in South China, i.e. shale gas preservation conditions and pore pressure, and the research on ground stress and natural microfracture systems should be strengthened. Then, systematic analysis was conducted by integrating shale gas multidisciplinary data and geological and engineering integration study was carried out. Finally, a 3D model, which was composed of “geophysics, reservoir geology, fracture system and rock geomechanics”, was established for shale gas reservoirs. Application practice shows that the geological engineering integration and the 3D reservoir modeling are effective methods for evaluating the shale gas sweet spots in complex marine mountains in South China. Besides, based on shale gas sweet spot evaluation, 3D spatial congruency and superposition effects of multiple attributes and multiple evaluation parameters are presented. Moreover, the short-plate principle is the factor controlling the distribution patterns and evaluation results of shale gas sweet spots. It is concluded that this comprehensive evaluation method is innovative and effective in avoiding complex geological and engineering risks, so it is of guiding significance in exploration and development of marine shale gas in South China.

Complex tectonic movements and high thermal maturity of marine shale dominate South China, where preservation conditions are critical for shale gas enrichment and productivity. Based on the exploration practices of the Silurian shale gas at the southeastern margin of the Sichuan Basin in recent years, conventional gas and shale gas were compared in terms of their preservation conditions. The results revealed that superior roof and floor conditions are indispensable to shale gas preservation. Moreover, the self-sealing ability and the huge gap of up to 2–8 times between vertical and lateral permeability of shale gas reservoirs determine the lateral diffusion as the basic pattern of shale gas migration. The unconformity at the bottom of Lower Cambrian leads to worse preservation conditions in the system, and cutting by faults may accelerate the diffusion of shale gas. Major controlling factors for shale gas preservation and their criteria of discrimination were also investigated. It is suggested that: (1) the strength of tectonic modification is the major factor controlling shale gas preservation. Broad and gentle structures with continuous seals and an anticlinal setting are more favorable for the enrichment of shale gas, and a closed evolutionary environment with late uplifting is more favorable for the preservation of shale gas; (2) shale gas can be preserved well in downdip areas without faults or effectively closed or shielded by faults and areas far away from outcrops or zones with stratigraphic hiatus; (3) pressure coefficient is a comprehensive indicator for discriminating preservation conditions. In the study area, the pressure coefficient is in positive correlation with shale gas production and the high or super-high pressure of reservoir is a signal of good preservation condition for shale gas; and (4) in the areas within the southeastern Sichuan Basin, other than those close to erosion zones or hiatus, the Wufeng Fm. of Upper Ordovician and the Longmaxi Fm. of Lower Silurian present high pressure coefficient (up to 2.25) generally, demonstrating good preservation conditions for shale gas, while the pressure coefficient reduces progressively toward or outside the margin of the basin, corresponding to downgrading preservation conditions.

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)