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• CH 4 and (sub and supercritical) CO 2 adsorption experiments on shales were performed. • The adsorption ratio of CO 2 over CH 4 for tested shale samples ranges from 1.66–8.32. • Langmuir, D-A, D-R and Ono-Kondo models were fitted to the adsorption data. • The favorable models used to fit CH 4 and CO 2 adsorption on shales are recommended. A thorough study of the adsorption behavior of shales to methane (CH 4) and carbon dioxide (CO 2) is critical for carbon dioxide sequestration in shale gas reservoirs and enhanced shale gas recovery. This paper discusses the results of an adsorption study of CH 4 and CO 2 , in single gas environment, on a set of shale samples taken from the Sichuan and Ordos Basins. The results indicated that shale exhibit higher affinity to CO 2 as compared to CH 4 under similar pressure and temperature conditions, and the preferential adsorption ratio of CO 2 over CH 4 varies between 1.66 and 8.32. Furthermore, the experimental data were modeled using Langmuir, Dubibin-Astakhov (D-A), Dubinin-Redushckevich (D-R) and Ono-Kondo models. The accuracy of the models in quantifying CH 4 and CO 2 adsorption on shale was compared using an error analysis technique. For CH 4 , both of Langmuir and D-A models performed satisfactorily with comparable accuracy. For subcritical CO 2 , the performance of the D-A model is the best. However, for supercritical CO 2 , Ono-Kondo model fitted the experimental data the best, which is the proposed model to use. The results of this study can provide the basis for the estimation of the CO 2 sequestration capacity in shale formations. [ABSTRACT FROM AUTHOR]

• Microstructures of the outcrop/core kerogen were systematically characterized. • Differences in chemical structure between the outcrop/core kerogen were identified. • Realistic 2D/3D molecular models of the outcrop/core kerogen were constructed. • Validity of the proposed molecular models was verified by gravimetric adsorption. • Effect of the kerogen microstructure on CH 4 adsorption behavior was investigated. It has been known that adsorbed gas, mainly CH 4 , serves as the dominant source of shale gas yield in the middle and later stages of reservoir exploitation. Therefore, it is of great significance to study the microstructure of kerogen (organic matter rich in shale) and its effect on CH 4 adsorption characteristics. In this paper, for the first time, a comparative study was conducted to experimentally characterize the microstructure of both outcrop and core kerogen samples from Longmaxi Shale, Sichuan Basin, SW China, using 13C NMR, FTIR, and XPS. Great differences in the chemical structure such as carbon skeleton (e.g. , aromaticity, aliphatic branch) and heteroatoms (e.g. , distribution and proportion of various types of functional groups) between the two kerogen samples have been identified. Molecular models of the outcrop and core kerogen samples were constructed based on the experimental data, that is, C 237 H 219 O 21 N 5 S 4 for the former and C 239 H 175 O 27 N 5 S 4 for the latter. CH 4 adsorption isotherms obtained from gravimetric adsorption test and molecular simulation using proposed kerogen molecular models are in reasonable agreement with each other, especially at low-pressure range. Interestingly, the adsorption capacity of CH 4 in the core sample is found higher than that in the outcrop sample under the same condition, indicating the effect of kerogen microstructure on CH 4 adsorption behavior. As a result, to precisely evaluate the adsorbed gas content in shale gas reservoirs, it is strongly recommended to use a core sample rather than an outcrop sample. [ABSTRACT FROM AUTHOR]

In this paper, the core shale samples from the Lower Longmaxi Formation (LF) in the southwest of the Sichuan Basin of China are carried out laboratory experiments to investigate the wettability and adsorption characteristics. The influences of the wettability on the development of the shale gas reservoirs were discussed. And the influences of the kerogen and the pure mineral on the methane adsorption capacity were discussed. The differences between the methane adsorption capacity of the pure mineral and the mixed minerals were also discussed. The results show that the spontaneous imbibition rate of the LF shale samples tended to rise firstly and then become stable with the increasing of the time; The spontaneous imbibition rate of water was higher than the spontaneous imbibition rate of oil; The methane adsorption capacity on the kerogen and the pure minerals first increased rapidly and then increased slowly and tended to be stable with the increasing of the pressure; The methane adsorption capacity on the kerogen was much larger than the different pure minerals; And among the different pure minerals, the order of the methane adsorption capacity is that: illite > chlorite > quartz; The water molecules would reduce the methane adsorption capacity on the Kerogen; The methane adsorption capacity of the mixed minerals can be approximately equal to the sum of the methane adsorption capacity of the pure minerals calculated by the mass ratios. The water blocking damage in the shale formation can’t be assessed according to the water blocking damage evaluation system of the conventional oil and gas reservoirs. The mixed wettability, the influence of the water on the methane adsorption capacity and water-induced cracks should be considered in the water blocking damage evaluation system of the shale reservoir. [ABSTRACT FROM AUTHOR]

Deep shale gas reservoirs, compared to shallow and intermediate shale gas reservoirs, usually exhibit lower fracture complexity, smaller stimulated volume, poorer conductivity, and faster production decline when the same injection scheme and construction parameters are used. As a result, specific injection scenarios for deep shale reservoirs must be investigated. In this paper, a series of laboratory fracturing tests were conducted to investigate the influence of injection scenarios on deep shale hydraulic fracture initiation and propagation. The black shale of the Lower Silurian Longmaxi formation in the Sichuan Basin was adopted, and four different injection schemes (constant fluid rate injection, cyclic injection, shut-in intermittent injection, and low-frequency pulse pressurization injection) were utilized in these experiments. The energy evolution during hydraulic fracturing with different injection schemes was analyzed by an array of acoustic emission (AE) sensors. Furthermore, the internal fracture geometry of the shale specimens after failure was determined using high-resolution CT scanning. Two parameters, fracture bulk density and fractal dimension were defined to quantitatively characterize the post-pressure fracture complexity. The results indicate that the rock breakdown pressure rises rapidly as the injection rate increases, for conventional monotonic rate injection. Although increasing the injection rate can serve the purpose of increasing the net pressure in the seam and enhancing the fracture complexity, it makes it easier to approach the equipment pressure limit. Unlike conventional hydraulic fracturing, which mainly induces tensile fractures near the wellbore, cyclic fracturing is more likely to cause fatigue damage to the rock, resulting in the formation of subcritical microcracks, which gradually grow into macroscale fractures. In addition, the cyclic injection method can reduce the rock breakdown pressure by approximately 24% compared with the conventional continuous injection method. The shut-in intermittent injection method can also reduce the breakdown pressure of shale by 22%, but this method is not conducive to enhancing the fracture complexity. Pulse fracturing creates the most complex fracture morphology among the four injection schemes tested. The rapid changes in wellbore pressure over a short time can easily result in the formation of multiple fractures around the borehole. Our experimental results and theoretical analysis can provide theoretical support for the optimization of injection schemes for deep shale hydraulic fracturing. • Laboratory tests were conducted to investigate the influence of injection scenarios on deep shale hydraulic fracturing. • All the experiments were monitored by an array of AE sensors. • The internal fractures geometry of the shale specimens after failure was determined by high-resolution CT scanning. • The cyclic fracturing can reduce the breakdown pressure by about 24% compared with the conventional continuous injection method. [ABSTRACT FROM AUTHOR]

An appropriate shut-in after fracturing can dramatically enhance performance of wells in shale gas reservoirs. In this study, a novel wettability index and mineral content curve based shut-in time optimization approach was proposed. First, a new experimental device for spontaneous imbibition of fracturing fluid under the conditions of formation temperature and confining pressure was designed. Then, we conduct a set of experiments on shale samples from the Longmaxi Formation (LF) in the Sichuan Basin to measure the water-wet index and determine the critical value of clay content. Finally, the low-field nuclear magnetic resonance (NMR) equipment was used to monitor the water flow in shale micro-pores, based on this, the shut-in time for different shale reservoirs was optimized. The experimental results show that LF shale hydration can induce new micro-fractures, and the fractures shape is mainly shale bedding fractures, with obvious directionality. The clay content is the key factor affecting water wettability of shale and the critical clay content value of type I and type II shale reservoirs was about 39.5%. The optimal shut-in time of type I and type II shale reservoirs are about 20 days and 15 days respectively. Field application of three wells showed that the average daily gas production was increased by 2–3 times. The research results can guide the development of shale gas reservoirs effectively. • In this paper, the water imbibition experiment of shale under the condition of formation temperature and pressure of shale reservoir was carried out, and the critical clay content affecting the imbibition capacity of shale was determined. • On this basis, the shut-in-time of different reservoirs types was further optimized. • The research results play an important guiding role in understanding the flow law of fracturing fluid in shale reservoirs. [ABSTRACT FROM AUTHOR]

The Longmaxi Formation has abundant shale gas resources. High-yield wells have been obtained in medium-shallow and deep areas in the Sichuan Basin. Quantitative research on the brittle-ductile change in rocks is a basic geological component for caprock evaluation, and it can also be applied to shale gas exploration. This paper fully considers the difference between the lower shale (N1) and upper shale (N2) of the Longmaxi gas-bearing shale. Through total organic carbon (TOC), mineral components, field emission scanning electron microscopy (FE-SEM), and triaxial mechanics experiments, the two groups of shale samples, N1 and N2, were compared and analyzed, and the brittle-ductile transition was quantitatively studied. Based on previous work, a method for the fast calculation of the key over consolidation ratio (OCR) was proposed. The results show that N1 is mainly organic-rich siliceous shale, N2 is primarily organic-poor clay shale and mixed shale, and N1 is generally more brittle than N2. The key OCRs of N1 and N2 are 2.16 and 2.60, respectively. The key confining pressures at which N1 and N2 become fully ductile are 87.87 MPa and 70.28 MPa, respectively. Therefore, the key depths of the brittle zones of N1 and N2 (H b1 and H b2) and the key depths of the ductile zones of N1 and N2 (H d1 and H d2) are obtained. On this basis, a comprehensive model for the Longmaxi shale gas' brittle-ductile transition exploration zone in the Sichuan Basin and H b1 and H b2 maps of the Longmaxi gas-bearing shale have been established. Through comprehensive vertical and horizontal analysis, Longmaxi shale gas exploration risks in different blocks of the Sichuan Basin have been clarified. Therefore, this study of the variation in the brittle-ductile transition has an important guiding role in refining the exploration of Longmaxi shale gas in the Sichuan Basin. • There are obvious differences between the lower shale and the upper shale. • Difference of brittle-ductile transition makes shale gas exploration more complicated. • The new method can quickly calculate the threshold value of over consolidation ratio. • The new model provides more comprehensive guidance for shale gas exploration. [ABSTRACT FROM AUTHOR]

Fractures gradually open under the action of fluid pressure in drilling shale gas reservoirs because of the existence of shale natural fractures, which leads to the leakage of expansible fractures. Induced fracture leakage is difficult to find and control in the early stage of drilling, resulting in great economic losses. The current model of induced fracture leakage pressure model is based on takes rock fracture criterion, which can only be used to judge whether the fracture is fractures created or not but cannot analyze the influence of fracture width change on leakage pressure after natural fracture of shale cracking. In addition, the model cannot control the occurrence of leakage. In this paper, the calculation method of fracture's width change under induced pressure is established. According to the field leakage rate data, a dynamic model of leakage pressure is established based on the parameters of time, leakage rate, fracture's width, fluid viscosity, and wellbore radius. The model is applied to calculate the dynamic change of leakage pressure on the Sichuan Shale Gas Field site and control the induced fracture's change to control leakage. Results show the following observations. (i) The fracture's width and leakage velocity of induced fracture increase with the increase of leakage pressure. Blocking the leakage when any leakage is found on the site is not advisable because it can increase the fracture's width artificially and increase leakage. (ii) The critical value of the fracture's width may cause severe leakage. When the leakage's differential pressure remains unchanged, the relationship between the fracture's width and leakage velocity refers to the power exponent change. The method of controlling the leakage pressure and reducing the fracture's width that is less than the critical leakage fracture degree is adopted for the leakage of the shale gas drilling in the Longmaxi Formation field Jiaoshiba, which effectively reduces the leakage amount. Taking a particular project, for example, controlling leakage pressure of induced fracture is given to verify the feasibility of the method. • The calculation method of fracture's width change under induced pressure is established. • A modal of leakage pressure is established based on time,leakage rate,fracture's width,and fluid viscosity. • The method of controlling the pressure to reduce the fracture's width to control the leakage is established. [ABSTRACT FROM AUTHOR]

Based on low-temperature thermochronological data (i.e., apatite fission-track (AFT) and (U–Th)/He (AHe)), structural evolution, burial and thermal history, this paper examines the relationship of multi-stage evolution between the upper Ordovician Wufeng and lower Silurian Longmaxi formations (i.e., the WL formation) and rapid exhumation at the Changning shale gas field in the southern Sichuan basin. AFT ages are generally young from southeast to northwest, decreasing from ca. 40 to 15 Ma while AHe single-grain ages range from ~35 to ~5 Ma. Inverse thermal histories show that a multi-stage cooling history with initial cooling began in the Late Cretaceous to early Cenozoic (middle Eocene), followed by accelerated rapid cooling in the late Cenozoic, with cooling rates of 2–4 °C/Myr across the Changning shale gas field. In particular, thermal models of samples in the western Changning area show a substantial increase in the cooling rates, i.e., from less than 1 °C/Myr to 3–5 °C/Myr in the Miocene. Integrated with inverse T-t models of low-temperature thermochronological data, the burial history indicates a four-stage thermal evolution of the WL Formation in the Changning shale-gas field: Early Mature from the middle Silurian to middle Permian, Middle Mature from the late Permian to Late Triassic, Late Mature from the Early Jurassic to Early Cretaceous, and Over mature since the middle Cretaceous, reaching a maximum burial depth of ~6000 m and maximum temperature of 190–200 °C at ca. 70–80 Ma. This evolution further suggests that a normal hydrostatic pressure index dominated the WL Formations in the Paleozoic. The gas generation and pressure index, however, have substantially increased since the Late Jurassic, particularly from the Early to middle Cretaceous, with a maximum pressure index of 2.1, which is indicative of the main shale gas accumulation and enrichment period in the WL Formation. Post-gas-generation structural deformation, uplift, and exhumation had a significant impact on shale gas enrichment, mainly through their influence on shale gas preservation. This suggests some relationships among the higher pressure coefficient of the WL Formation, the higher productivity and total gas content of the WL Formation, a weaker post-gas-generation structural deformation, and a weaker uplift, as indicated by the erosion and burial depth across the Changning shale gas field. Due to a significantly stronger cooling and uplift that occurred the in Late Cenozoic across the western Changning area, the pressure index decreased rapidly from ~2.0 to 1.0 with a normal pressure condition, indicating the destruction of the reservation condition in the WL Formation. • New low-temperature thermochronological data was from the SE Sichuan basin. • An accelerated cooling in the late Cenozoic was found. • Post-gas-generation deformation and exhumation controlled the shale gas enrichment. [ABSTRACT FROM AUTHOR]

The Lower Paleozoic Ordovician Wufeng Formation and the Silurian Longmaxi Formation shale in the southeastern part of Sichuan Basin in China are the key strata for shale gas exploration. In this paper, based on a large number of outcrops, cores and natural gamma spectroscopy logs combined with scanning electron microscopy, geochemical parameter testing and mineral component analysis, the geological conditions and exploration potential of shale gas accumulation were studied in this area, and the relationship between structure and shale gas preservation is discussed. The vertical reduction in the U/Th ratio measured in the outcrop sandstone lenses and core horizontal bedding and observed in the energy spectrum logs indicates that the sedimentary water body transformed from a low-energy anoxic reducing environment to a high-energy oxidizing environment. The TI index and the kerogen carbon isotope indicate that the organic matter type of the shale is mainly type I kerogen. The TOC content of high-quality shale is generally above 2.50%, and the R o value is between 2.00% and 3.08%. High organic matter abundance, moderate thermal evolution and a large thickness of high-quality shale ensure an adequate supply of hydrocarbon resources. Multiple types of inorganic pores, primary organic pores and pores formed during hydrocarbon generation provide abundant reservoir space for the enrichment of shale gas. The tectonics have an important influence on the preservation of shale gas. Moderate fracture development, a late tectonic uplift time, small-scale tectonic uplift, and high formation pressure coefficient are conducive to the preservation of shale gas, and the gas content and productivity will be higher. Overall, a structural stability zone with a high formation pressure coefficient is a favorable area for shale gas exploration. • Comprehensive analysis the sedimentary environment based on three scales: outcrop, core and energy spectrum logging. • Later and small-scale tectonic uplift, moderate fracture development, good roof preservation are conducive to gas enrichment. • A structural stability zone with a high formation pressure coefficient is a favorable area for shale gas exploration. [ABSTRACT FROM AUTHOR]

The Upper Ordovician Wufeng Formation and Lower Silurian Longmaxi Formation marine shale are the major shale gas exploration and development target in the Middle-Upper Yangtze region. Although three national shale gas demonstration areas have been built and several high-yield shale gas wells have been discovered in the Wufeng Formation and Longmaxi Formation, shale gas in these areas has not been fully commercialized because the enrichment degree of shale gas varies greatly in different tectonic settings. By analyzing the formation processes and distribution characteristics of the organic-rich shale, reconstructing the burial history and hydrocarbon generation history, and comparing the shale gas enrichment and preservation conditions in different tectonic settings in South China, this paper points out that (1) The craton depression and foreland basin on the cratonic margin are favorable zones for the development of organic-rich shale. Because the Yangtze plate is small, the foreland basin is greatly affected by the input of terrigenous clastic and the thickness and area of organic-rich shale in the craton basin is larger than that in the foreland basin. The organic-rich shale is mainly distributed in south Sichuan deep-water shelf and west Hubei-east Chongqing deep-water shelf, and the enrichment interval is the Dillcellograptus complexus-Cystograptus Vesicolus graptolite zone from the Wufeng Formation to the bottom of Longmaxi Formation are favorable intervals for shale gas enrichment. (2) Since the Late Jurassic, significant differential intracontinental tectonic deformation, uplift and denudation occurred in the Middle-Upper Yangtze region. Moderate compression and uplift were beneficial to the development of micro-fractures and bedding fractures in shale, resulting in good preservation conditions of shale gas reservoirs with a high-pressure coefficient. In contrast, strongly deformed areas, where faults and high-angle large fractures were developed, are not conducive to the preservation of shale gas reservoirs. (3) The craton depression of the Middle-Upper Yangtze region, where organic-rich shale was deposited, is favorable to shale gas enrichment because it provides a good material basis, and also a relatively stable and compression-resistant tectonic environment for later tectonic deformation and uplift-derived destruction. Based on the analysis and evaluation of tectonic construction–transformation conditions under the macro-control of plate tectonics, it can well explain the existing commercial shale gas discoveries and failure cases and can guide the optimization of future exploration targets. • ►Deep water in the craton depression controlled the distribution of organic-rich shale. • Stable tectonic settings are favorable for shale gas enrichments. • Two depressions in Yangtze Craton are the most favorable areas for shale gas accumulation. [ABSTRACT FROM AUTHOR]

The initial water saturation of shale reservoirs is in general lower than the irreducible water saturation. However, the hydraulic fracture network region is highly saturated by fracturing fluid, which results in a two-phase flow inside fractured region. A long-time two-phase flow period is always observed in the fields even after a high flowback rate, which cannot be explained by existing models. In this paper, we develop a 2D gas-water flow model coupling multi-scale discrete fractures and continuum framework to describe the flowback process of a multi-stage fractured horizontal well in shale gas reservoirs. The model considers the non-linear flow mechanism of free gas, desorption of adsorbed gas and the co-existence of single gas flow and gas-water flow. The capillary pressure model and relative permeability model are both employed with different parameter values for matrix and fractures, respectively. The permeability of naturally fractured shale is described using a fractal model. To overcome non-convergence problem of finite element method for solving two-phase flow in cross fractures, the model is solved by finite element method and finite volume method. The model is verified through a simple two-phase flow simulation and a single gas phase simulation with some simplifications. Then the model is used for history matching as well as production prediction of a well in Changning block, Sichuan, China. The simulation results show that the high water saturation induced "skin factor" in the vicinity of hydraulic fractures significantly delays the gas production for a long time because some of the fracturing fluids become irreducible water and lower the gas phase permeability. Due to the great influence of fracture interference on water flow, the fracturing fluids concentrate on regions near hydraulic fractures and their junctions. The long-term gas production of the complex fracture network is slightly higher than that of the simple fracture network, which is different with the simulation results of single gas flow model. • A physical model where the gas-water coexists with single gas flow is built. • The viscous flow, Knudsen diffusion and adsorption / desorption phenomenon are considered of the gas flow in shale matrix. • The finite element method (FEM) and the finite volume method (FVM) are employed to solve the mathematical model. • The flowback and production process can be simulated continuously. [ABSTRACT FROM AUTHOR]