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Marine–continental transitional shale is one of the most promising targets for shale gas exploration in the Lower Yangtze region. To investigate the sedimentary environments and the regularity of the enrichment of the Longtan shale, multiple techniques including core and thin-section observations, geochemical and elemental analyses, X-ray diffraction, scanning electron microscopy (SEM), and low-pressure nitrogen adsorption (LPNA) were used to analyze the sedimentology, mineralogy, and pore structure of the Longtan shale. The core descriptions and thin-section observations showed that the Longtan shale was deposited in marine–delta transitional environments including delta-front, shore swamp, mixed tidal flat and shallow shelf environments. The Sr/Cu, V/Cr, CIA, EF (Mo), EF (U), and other major and trace element results indicated warm and moist climates and water-reducing conditions in the Longtan period. Both the climate and water conditions were favorable for organic matter production and preservation. The geochemical results showed that the Longtan shale was in the overmature stage (Ro values ranging from 2.4% to 3.57%) and that the average total organic carbon (TOC) content was 5.76%. The pore system of the Longtan shale consisted of inorganic pores with a small number of organic pores and microfractures. The porosity and specific surface area were mainly affected by the TOC and clay mineral contents. An effective combination of brittle mineral particles, organic matter, and clay minerals provided the necessary conditions for pore preservation. The organic pores, intergranular pores in clay minerals, and brittle mineral pores formed the main network system for the Longtan shale. In summary, the lithological combinations, organic geochemistry, and pore structure system were all affected by the sedimentary environments.

Currently, Luzhou in the Sichuan Basin is a focal point for shale-gas exploration and development in China. However, a lack of detailed research on the mineral composition of the Wufeng Formation-Longmaxi Formation (WF-LF) shale is hindering the extraction of deep-buried shale gas in the Luzhou shale play. Herein, a field emission scanning electron microscope (FESEM) equipped with the Advanced Mineral Identification and Characterization System (AMICS) software was employed to analyze the mineral composition of the WF-LF shale from six wells in Luzhou. Quartz was the dominant mineral type, (16.9–87.21%, average 51.33%), followed by illite, calcite, dolomite, and pyrite. Our study revealed that (1) quartz content showed a moderate positive correlation with the total organic carbon (TOC) content, indicating that the quartz found in the shale is mostly of biological origin; and (2) the sum content of siliceous minerals and carbonaceous minerals was moderately positively correlated with the brittleness index (BRIT) in well SS1H2-7 and in the well group of RS8 and RS5, indicating that the siliceous minerals and carbonaceous minerals had an active effect on reservoir compressibility. Finally, according to the mineralogical features of each sublayer, we identified four types of reservoirs to determine their scope for exploration.

Based on the lithologies, sedimentary structures, graptolite zones, inorganic geochemical characteristics, electrical data of 110 shale gas wells in southern Sichuan Basin and the mineral quantitative analysis technology of scanning electron microscope, the stratigraphic sequences of the Upper Ordovician Katian Stage–Himantian Stage–Silurian Rhuddanian Stage–Aeronian Stage are divided, the sedimentary characteristics and fourth-order sequence evolution are analyzed. The target layer can be divided into two sequences, namely SQ1 and SQ2. According to Ordovician–Silurian sedimentary background, the gamma value of the target layer and U/Th, 5 maximum flooding surfaces and 12 system tracts are identified. According to system tracts and their combinations, eight fourth-order sequences are identified, namely, Pss1–Pss8 from old to new. The development period and scale of dominant shale facies from Katian stage to Aeronian stage in southern Sichuan are restored. The best-quality dolomite/calcite-bearing siliceous shale facies, siliceous shale facies, clay-bearing siliceous shale facies and feldspar-bearing siliceous shale facies mainly occur in Pss3–Pss5 of Weiyuan, Western Chongqing and Luzhou, Pss6 of Western Changning– Northern Luzhou–Central Western Chongqing and Pss3–Pss4 of Changning. The siliceous clay shale facies second in quality mainly occurs in Pss6 of Southern Luzhou–Changning area (excluding Western Changning area), Pss7 of Eastern Weiyuan– Northern Western Chongqing–Southern Luzhou and Pss8 of Northern Luzhou–Weiyuan–Western Chongqing. The fourth-order sequence evolution model of Katian stage–Aeronian stage in southern Sichuan is established. During the depositional period of Pss1–Pss8, the sea level had six regressions and five transgressions, and the first transgression SQ2-MFS1 after glaciation was the largest flooding surface.

In this study, shale cores from 20 wells in the S1l11-1 sublayer of Longmaxi Formation buried in shallow shale (3500 m) in the southern Sichuan Basin, China were collected to compare their pore structures and gas-bearing properties using multiple experiments. Results showed that the deep layer has relatively lower brittle mineral content, which is disadvantageous in terms of the higher requirements it imposes on hydraulic fracturing. Results also showed that the most important factor controlling the differential enrichment of S1l11-1 shale gas in southern Sichuan Basin is porosity. Moreover, the porosity composition of shallow shale and deep shale has significant differences: the porosity of shallow shale is dominated by organic pores, while for deep shale, both organic and inorganic pores are important. The inorganic pores provide significant storage space for free gas in deep shale; their contribution warrants more attention. We also found that the difference in organic porosity of the shallow and deep shale samples resulted from large differences in pore development ability, while the highest inorganic porosity was concentrated near the optimal mineral composition when the content of quartz plus feldspar plus pyrite was about 70%. This study revealed the primary factor controlling the difference in gas content between shallow and deep shale and detailed the characteristics of microscopic pore structure, providing a basis for the exploration and development of deep shale gas in the Wufeng-Longmaxi Formation in the southern Sichuan Basin.

Ascertaining the characteristics of fracture system at different scales integratedly is very important for performing efficient exploration and development activities of specific shale gas reservoirs. In this paper, an area around 250 square kilometers in Changning Block of Sichuan Basin is taken as an example, which belongs to Chinese Shale Gas Development Demonstration Plot. Seismic structural interpretation was performed detailedly based on original seismic amplitude cube and derived edge-detection cubes, and then the technologies of finite element horizon flattening, orthogonal decomposition principal component analysis, seismic discontinuity patch auto-extraction and paleo-stress field inversion were applied, together with the existing regional geological understanding and fracture information in wells, to figure out the staging and grouping of fracture system at seismic scale (i.e., at large and middle scales), at the same time to clarify the regional tectonic evolution and its genetic relationship with fractures at different scales such as the ones revealed by seismic data and cores or image logs. The following conclusions were reached. (a) The tectonic movements affecting the development of fracture system in study interval mainly happened during Yanshanian-Himalayan periods, i.e., 3 compressional tectonic episodes which were nearly in S-N direction in Late Yanshanian period, in NNE-SSW direction in Early Himalayan period, and in NWW-SEE direction in Middle Himalayan period respectively. (b) The Late Yanshanian tectonic event primarily formed long-axis anticlines and synclines, thrust faults and fault-related fractures, all of which were nearly in E-W trending, and fold-related fractures in different directions. (c) The Early Himalayan tectonic event mainly formed genetically related conjugate fracture sets including strike-slip faults and shear fractures both in NNW and NE directions, and transverse extensional fractures. (d) The Middle Himalayan tectonic event chiefly formed thrust faults, and related fractures and folds in NNE~NE direction, and transverse extensional fractures. (e) Furtherly our work demonstrated that such kind of fracture system analysis was of great significance in building discrete fracture network, providing precautionary advice for drilling engineering, and optimizing completion program and field development plan, etc. Hence, integrated fracture system analysis at full scales to reach more meaningful and robust conclusions is essential work for unconventional resources evaluation and characterization.

SummaryCurrently, there is large-scale shale gas exploration and development in the Sichuan Basin, western China. Caused by high tectonic stress and presence of fracture systems at various scales in the lower Silurian Longmaxi reservoir formation, hydraulic fracturing in shale gas reservoirs in the Sichuan Basin has encountered many difficulties, such as placing sufficient proppant, poor-production performance for some wells, and ambiguity as to the factors controlling the production of reservoirs. It has been recognized that lack of geomechanical understanding of the shale gas reservoirs is a major obstacle to effectively addressing these difficulties.A 3D full-field geomechanics model was constructed for the Changning shale gas reservoir in the Sichuan Basin through integrating seismic, geological structure, log, and core data by following a newly formulated work flow. The 3D geomechanical model includes 3D anisotropic mechanical properties, 3D pore pressure, and the 3D in-situ stress field. Through leveraging measurements from an advanced sonic tool and core data, the anisotropy of the formation was captured at wellbores and propagated to 3D space guided by prestack seismic inversion data. The 3D pore-pressure prediction was conducted with seismic data, and calibrated against pressure measurements, mud-logging data, and flowback data. A discrete-fracture-network (DFN) model, which represents multiscale natural-fracture systems, was integrated into the 3D geomechanical model during stress modeling to reflect the disturbance on the in-situ stress field by the presence of the natural-fracture systems.The 3D pore-pressure model was used to calculate more-reliable estimates of gas in place in the shale gas reservoir, and the geomechanical model was used to reveal the root cause of difficulties of proppant placement in this tectonically active and unevenly fractured shale gas reservoir.The paper presents the highlights and innovations in constructing the 3D geomechanical model for the shale gas reservoir, and explains how the 3D geomechanical model is used to address technical challenges encountered during drilling and completion. Also, it demonstrates that a reliable 3D geomechanical model, with proper characterization of anisotropy, pore pressure, and natural fractures, provides a critical opportunity to improve the development in this shale gas reservoir.

The Lungmachi Formation is widely distributed in Guizhou, Chongqing and the adjacent area. It is important for the study of Silurian biostratigraphy and shale-gas investigation. Based on those biostratigraphically well-studied sections from Guiyang to Huayingshan, we reveal the stage-progressive distribution pattern of the Lungmachi black shales. The distribution of the Lungmachi black shales in the studying area can be subdivided into four geographic belts from the south to the north, reflecting the joint effect of regional and global environmental changes. The graptolite depth zonation model was adopted herein to infer the water depth of major graptolite assemblages from the black shales. The changes in the water depth indicate two major stages. The first stage is named the transgressive distribution stage which ranged from the Persculptograptus persculptus Biozone (LM1, upper Hirnantian) to the Coronograptus cyphus Biozone (LM5, upper Rhuddanian), an interval mostly controlled by global sea-level rise. The second stage, ranging from the Demirastrites triangulatus Biozone (LM6, lower Aeronian) to the Spirograptus guerichi Biozone (LM9, lower Telychian), is named the regressive shrinking stage, during which the black shales were gradually replaced by mixed-facies or carbonate sediments from the south to the north, representing the effects of the persistent uplifting of the Central Guizhou Oldland.

Ning201 Longmaxi shale gas play is located on the southwest edge of Sichuan Basin. Block Ning201 surface is very mountainous and elevation range of drilling pads is between 400 meters and 1300 meters. The target layer of shale gas exploration and development is mainly the Wufeng Formation of the Ordovician system and the organic-rich shale interval of the Lower Longxixi Formation of the Silurian system. The total thickness is between 30m and 50m, and the overall buried depth is 2300~3200m. Field development of Ning201 shale gas play was geared up in 2014. During early appraisal phase before 2014, average testing results of wells were 10~15×104 m3/d. 7 vertical appraisal wells and 50 horizontal wells have been drilled and 38 horizontal wells among them have been put into production to evaluate optimized development strategy until middle of 2017. Changning area accomplished the construction of 15×108 m3/a production capacity. During production appraisal phase, different well spacing pads were configured, and some cross-well interference testing were performed to determine optimal spacing in Ning201 block. Only qualitatively understanding can be achieved with spontaneous field efforts and quantitative evaluation of long-term impacts on production with varying initial rate control and well spacing is still missing. In this paper, an integrated modeling workflow was introduced to accurately simulate the production behavior of a representative shale gas well and to control production through a calibration model to optimize well spacing and maximize economic returns. The workflow begins with microseismic monitoring during shale gas well fracturing operations. Considering the fracturing pumping procedure, fluid and proppant volume and subsurface features, including formation, natural fractures and in-situ stresses, the heterogeneity of the hydraulic fracturing system propagation ensures that the simulated complex hydraulic fracturing network is in line with reality. After establishing a detailed hydraulic fracturing model, production performance is matched to history to better calibrate the conductivity of hydraulic fracture network in dynamic model as a relaible predicting tool.

Changning National Shale Gas Demonstration Area was established in 2012. Field Development of its Ning201 shale gas fields was geared up in 2014. By 2015, Changning area accomplished the construction of 15×108 m3/a production capacity. During early appraisal phase before 2014, average testing results of wells were 10~15×104 m3/d. In the end of 2016 and early 2017, average testing results of large numbers of wells across multiple pads achieved over 25×104 m3/d. Overall testing results of some pads have exceeded 180×104 m3/d per pad, and some of them may exceed 180×104 m3/d per pad in soon future. Through implementing geo-engineering integration, efficiency and effectiveness of field development have been steadily enhanced. This paper reviews our practices to establish and rapidly evolve the learning curve in this national demonstration area through geoengineering integration. Benefiting from geo-engineering integrated study, development options were systematically, proactively and effectively supported throughout the process of field development. Per the evolving understanding of reservoir and engineering challenges, adaptive technology and engineering solutions were exploited and optimized. A new geo-engineering model has been proposed which covers engineering applications of drilling, completion, production and development. Based on our gathered knowledge and experience, key contributing factors for marine shale gas development in Sichuan basin were thoroughly studied and summarized. They may include controlling factors of productivity, optimum production scheme, optimized well spacing, and so on. This paper also points out key areas for further improvement and enhancement in future.

Currently, there is large-scale shale gas exploration and development in the Sichuan basin, western China. Due to high tectonic stress and presence of fracture systems at various scales in the lower Silurian Longmaxi reservoir formation, hydraulic fracturing in shale gas reservoirs in the Sichuan basin has encountered many difficulties, such as difficulty in placing sufficient proppant, poor production performance for some wells, and ambiguity as to the factors controlling production of the reservoir. It has been recognized that lack of geomechanical understanding of the shale gas reservoirs places a major obstacle to effectively addressing these difficulties. A 3D full field geomechanics model was constructed for Changning shale gas reservoir in Sichuan basin through integrating seismic, geological structure, log, and core data by following a newly formulated integrated workflow. The 3D geomechanical model includes 3D anisotropic mechanical properties, 3D pore pressure, and the 3D in-situ stress field. Through leveraging measurements from an advanced sonic tool and core data, the anisotropy of the formation was captured at wellbores and propagated to 3D space guided by prestack seismic inversion data. 3D pore pressure prediction was conducted using seismic data and calibrated against pressure measurements, mud logging data, and flowback data. A discrete fracture network model, which represents multiscale natural fracture systems, was integrated into the 3D geomechanical model during stress modeling to reflect the disturbance on the in-situ stress field by the presence of the natural fracture systems. The 3D pore pressure model was used to calculate more-reliable estimates of gas in place in the shale gas reservoir, and the geomechanical model was used to reveal the root cause of difficulties of proppant placement in this tectonically active and unevenly fractured shale gas reservoir. The paper presents the highlights and innovations in constructing the 3D geomechanical model for the shale gas reservoir and explains how the 3D geomechanical model is used to understand the root cause of poor proppant placement encountered during hydraulic fracturing and events such as mud losses during drilling. Hence, the modeling provides a critical opportunity to improve reservoir stimulation in the shale gas reservoir.

Shoaling is a common type of sedimentation in the evolution of carbonate platform, and commonly has poor continuity. This paper presents a newly discovered and rare type of shoaling, i.e., mega-shoaling in nearly basin scale, which is developed in the Middle Triassic Leikoupo Formation of the Sichuan Basin, southwest China. During the Leikoupo time, the studied Sichuan Basin experienced hot and dry climate conditions and developed a carbonate platform within a restricted epicontinental sea. In B sub-layer of the Lei-1-1 sub-member of the Leikoupo Formation a series of grainstones of shoal facies accumulated throughout almost the entire basin, thereby generating features associated with basin-scale mega-shoaling. By detailed core examination and microscopic observation of thin sections, it is shown that the lithology of this set of grainstones is dominated by doloarenite (calcarenite) followed by oolitic dolomite (limestone). In addition, it contains three types of sedimentary sequences characterized by upward-coarsening and upward-shallowing as the followings: restricted lagoon to platform interior beach; restricted lagoon to platform interior beach and to platform flat; and tidal flat to peritidal beach. Subsequently, a multicyclic stratigraphic division and correlation revealed that this set of grainstones can be well traced and compared horizontally, and is generally isochronous. In addition, a template for logging facies, established based on core calibrations and logging data, was employed to analyze the 235 wells in the basin. The results demonstrate the shoal grainstones to be 10–40 m thick with a 15×104 km2 continuous distribution area. These findings indicate that the carbonate platform developed mega-shoals within a short period of time. The genesis of such a mega-shoaling was investigated by focusing on various shoaling conditions, such as paleo-tectonics, paleo-geomorphology, paleo-climate, sea-level changes, and palaeo-hydrodynamics. A specific combination of independent geological factors creates beneficial geomorphologic conditions for the mega-shoaling including a quiescent paleo-tectonic environment, relatively flat paleo-geomorphology and evaporites filling up and leveling off. In addition, a stably settling carbonate platform underwent sea-level fluctuations through swift transgressions and protracted regressions, which is not only conducive to continuous, multicyclic and superimposed vertical development of grain beaches but also beneficial for the horizontal migration, coalescence and superimposition of individual grain beaches. As a consequence, large-scale and continuously-distributed grain beach sedimentation emerges and mega-shoals develop.