Shale Gas Reservoir Characterization Research Articles

Research on the Effect of Fracture Angle on Neutron Logging Results of Shale Gas Reservoirs

Fracture structures are important natural gas transport spaces in shale gas reservoirs, and their storage state in shale gas reservoirs seriously affects gas production and extraction efficiency. This work uses numerical modeling techniques to investigate the logging response law of the thermal and epithermal neutrons in the gas-containing fracture environment at various angles, applying neutron logging as a technical method. To increase the precision of the evaluation of the natural gas storage condition in shale gas reservoirs, the angle of the fractures’ neutron logging data is analyzed. It is found that even in an environment with the same porosity of the fractures, there are significant differences in the logging results due to the different angles of the fracture alignment: 1. the neutron counts in the high-angle (70–90°) fracture environment are 2.25 times higher than in the low-angle (0–20°), but the diffusion area of the neutrons is only 10.58% of that in the low-angle (0–20°); 2. in the neutron energy spectrum, neutron counts are spreading to the high-energy region (7–13 MeV) along with the increase in the angle of the fracture, and the feature is especially prominent in the approximately vertical (60–90°) fracture environment, which is an increase of 528.12% in comparison with the counts in the approximately horizontal angle (0–30°) environment. The main reason for these differences is the variation in the volume of the fracture within the source radiation. This volumetric difference results from the variation in fracture angles (even though the fracture porosity is the same). In view of the above phenomenon, this paper proposes the concept of “effective fracture volume”, which can intuitively reflect the degree of influence of fracture angle on neutron logging results. Further, based on the unique characteristics of shale gas reservoirs and neutrons, this paper provides important theoretical support for the modification of the porosity of the field operation, the evaluation of the physical characteristics of the gas endowment space, and the assessment.

Research on Production Prediction Method of Multi-stage Fractured Shale Gas Horizontal Well

Abstract Shale gas is a crucial component of unconventional energy. Productivity evaluation of gas wells is essential to ensure efficient and stable production. However, predicting productivity has been challenging due to the complex characteristics of shale gas reservoirs and the use of multi-stage fractured horizontal wells (MFHW) technology in the development process. This study compares traditional production prediction methods with an optimized least squares support vector machine model (LSSVM). The traditional productivity prediction method involves establishing a mathematical model of the MFHW in a fully enclosed rectangular shale formation. The model considers the effects of shale gas adsorption, diffusion, and pressure sensitivity. The model’s analytical solution is obtained using Duhamel’s principle, Laplace transform, and inverse transform. An independent production data analysis software is developed based on the analytical solution of bottom-hole pressure to predict production. To implement the LSSVM model, the model’s input parameters must be determined first. The LSSVM model’s regularization parameters and kernel parameters are obtained through the particle swarm optimization (PSO) algorithm, and the prediction model is established. The model’s matching is evaluated by calculating the coefficient of determination (R2) and the normalized root mean square error (NRMSE). The results indicate that the traditional production capacity prediction method is suitable for stable production in terms of applicability. However, the LSSVM model does not have this limitation and generally provides more accurate predictions throughout the entire production process. For complex shale gas reservoirs that frequently switch wells and use multi-stage fracturing technology, the LSSVM model is more suitable for predicting shale gas well productivity.

Petrophysical properties identification and estimation of the Wufeng-Longmaxi shale gas reservoirs: a case study from South-West China

Abstract Petrophysical properties are critical for shale gas reservoir characterization and simulation. The Wufeng-Longmaxi shale, in the south-eastern margin of the Sichuan Basin, is identified as a complex reservoir due to its variability in lithification and geological mechanisms. Thus, determining its characteristics is challenging. Based on wireline logs and pressure data analysis, a shale reservoir was identified, and petrophysical properties were described to obtain parameters to build a reservoir simulation model. The properties include shale volume, sand porosity, net reservoir thickness, total and effective porosities, and water saturation. Total and effective porosities were calculated using density method. Shale volume was estimated by applying the Clavier equation to gamma-ray responses. Sand porosity and net reservoir thickness were evaluated using the Thomas–Stieber model, and the Simandoux equation was used to compute water saturation. The results indicate that the reservoir is characterized by a relatively low porosity and high shale content, with shale unequally distributed in its laminated form (approximately 75%), dispersed (about 20%), and structural form (5%). This research workflow can efficiently evaluate shale reservoir parameters and provide a reliable approach for future reservoir development and fracture identification.

Shale Gas Reservoir Pore Pressure Prediction: A Case Study of the Wufeng–Longmaxi Formations in Sichuan Basin, Southwest China

Pore pressure prediction is critical for shale gas reservoir characterization and simulation. The Wufeng–Longmaxi shale, in the southeastern margin of the Sichuan Basin, is identified as a complex reservoir affected by overpressure generation mechanisms and variability in lithification. Thus, standard methods need to be adapted to consistently evaluate pore pressure in this basin. Based on wireline logs, formation pressure tests, and geological data, this study applied the Eaton–Yale approach, which extends the theoretical basis of Eaton and Bowers methods to reservoir geological conditions and basin history. The method was developed by integrating petrophysical properties, rock physics interpretations, and geology information. The essential steps include (1) a multi-mineral analysis to determine mineral and fluid volumes; (2) a determination of the normal pressure trend line and extending it to overpressured sections; (3) predicting pore pressure using the basic Eaton approach and identifying overpressured zones; (4) correcting compressional velocity using lithology logs and a rock physics model; (5) determining the Biot Alpha coefficient and vertical-effective stress and estimating the new pore pressure values using the Eaton–Yale method. Overpressure zones were corrected, and reservoir pore pressure varied between 30.354 and 34.959 MPa in the wells. These research results can provide a basis for building reservoir simulation models, identifying reservoir boundaries, and predicting relative permeability.

Significance of organo-mineralogical constituents on pore distribution, fractals and gas sorption mechanism of Permian shale beds in Korba sub-basin of the Son-Mahanadi Valley, India

In this study, shale samples obtained from the Korbasub-basin of Central India have been evaluated for the significance of organo-inorganic constituents in terms of their source potential of gas genesis, pore-matrix setup, and gas adsorption and desorption. The samples were analysed for various properties, such as megascopic features, lithological variations, depositional facies, and sources of organic and inorganic sediments. Also, maceral content, mineralogical constituents, kerogen type, pore distribution, pore structure, fractal characteristics and gas storage capacity were examined. The analysis revealed a trend of alternating bands of carbonaceous matter, silts, intercalations, and fluvial bedding lithofacies patterns indicating that the sediments were deposited under fluvio-terrestrial-lacustrine depositional conditions. Ternary facies analysis of maceral composition and van Krevelen diagram suggested the evolutionary path of type IV kerogen and are thermally matured source material located within the dry hydrocarbon generation window. Evaluation of pore types and pore structures using BET sorption plots (hysteresis H3 and isotherm type IV) revealed the presence of cylindrical, slit and combined cylindrical-slit pores with two distinct fractal characteristics. The discrete macerals underwent partial decomposition during transportation and mixing with inorganic components (clay and minerals), which influenced organic matter preservation, gas genesis, pore fractals and storage mechanism. The chemical index of alteration (CIA – 88.36 to 91.97), weathering (CIW – 96.60 to 98.80) and compositional variation (ICV – 0.31 to 0.70) demonstrated the influence of partial decomposition and strong weathering patterns on the organo-inorganic matter. A significant correlation was observed between pore fractals and elemental composition, particularly related to the resistance of weathering elements such as MgO, Al2O3, Fe2O3, SiO2, P2O5, TiO2, etc., which partially contributed to the formation of pore rugged surfaces. Microscopic and XRD analyses were employed to determine the mineral type, grain shape and size, and their amount leading to the development of the shales brittleness index (MBI). The importance of brittle characteristics, governed by minerals and clays within the shale, is discussed in relation to the hydro-fracturing technique for permeability enhancement. The results of high-pressure methane sorption indicated a moderate gas storage potential. The variation in sorption capacity (VL – 6.65 to 8.25 cc/g) is described through relationships with the ICV, pore diameter, pore volume, liptinite and total maceral content. Fractal dimensions D1 (2.4571–2.5611) and D2 (2.5804–2.7529) exhibited a direct relationship with adsorption properties, indicating the presence of rugged surfaces associated with meso- and macro-scale pores, which primarily control gas storage in shale. This research offers detailed insights into shale gas, providing valuable information for CBM and petroleum operators engaged in methane gas exploration and production. While commercial CBM production has been ongoing in India for over a decade, the exploration and understanding of shale gas reservoir characteristics are still in progress. This investigation adds significant value and highlights the extensive opportunities for research and potentially commercially recovering shale gas in the Korba sub-basin.

Fisher-Bayesian inversion for estimating shale gas facies

The classification of shale gas facies from seismic properties is critical for shale gas reservoir characterization. Shale gas facies are affected by many petrophysical properties. Therefore, the characterization of shale facies should be carried out by multiple parameters, which is more reasonable and accurate. However, multiparameter inversion often leads to unstable results, and coupled properties are generally a way of solving this problem. We develop a Fisher-Bayesian inversion method for estimating shale gas facies by combining the Fisher projection and Bayesian inversion method. The mathematical method adopted for the inversion is the Bayesian framework. The link between different facies and coupled properties is given by a joint prior distribution. We derive the analytical formulation of the Bayesian inversion under the Gaussian mixture assumption for coupled attributes and different shale gas facies. Our approach realizes the fusion of multidimensional petrophysical parameters and establishes a shale gas facies prediction method based on coupled properties. The application to real data sets delivers accurate and stable results, wherein shale gas facies and coupled attributes are accurately predicted and inversed.

Reservoir Characteristics and Gas Content of Black Shale of Wufeng-Longmaxi Formation in Qianjiang Area, Southeast Chongqing, China

The shale gas exploration in Changning, Weiyuan, Fuling Jiaoshiba, and other areas has achieved great success in the Sichuan Basin, and the basin margin of the Sichuan Basin will be an important target in the future. In view of the lack of understanding of shale gas reservoir characteristics of the basin margin area of the Sichuan Basin, this paper conducts a study on reservoir characteristics and gas-bearing properties of this area using qualitative and quantitative techniques. The results show that the thickness of the black shale reservoir in the Qianjiang area is up to 33 m, the kerogen sapropelic type (I) is dominant, and Ro ranges from 2.2 wt% to 3.39 wt%. The mineral composition is relatively complex, mainly composed of quartz and clay minerals. Quartz content is in the range between 9.4 wt% and 79 wt% ( average = 47.48 wt % ), while clay content is in the range between 10.02 wt% and 43.6 wt% ( average = 29.41 wt % ). There are various types of reservoir spaces, mainly including organic pores dominated by matrix pores, intergranular and intragranular pores, intergranular and intragranular dissolution pores, secondary dissolution pores, and microfractures, among which organic pores are the main pore types. The pore volume of nanopores is 0.009897-0.017177 cm3/g ( average = 0.01304 c m 3 / g ), and the specific surface area ranges from 12.1 m2/g to 35.1 m2/g ( average = 20.47 m 2 / g ). Micropores and mesopores are the main pore sizes for the development of organic pores. Quartz particles promote the development of reservoir space, while clay minerals are not conducive to the development of pores. The total gas content ranges from 0.5 m3/t to 4.43 m3/t ( average = 1.69 m 3 / t ). Its enrichment is controlled by many factors. The increase of organic matter abundance is the material basis for shale gas enrichment. The development of organic pores provides high-quality storage space for shale gas preservation. The development of different mineral components restricts the enrichment of shale gas.

Research and Application of Shale Gas Reservoir-Wellbore Integrated Model Coupling Method

As a representative of emerging unconventional energy, shale gas has the characteristics of large reserves, long production cycle, and environmental protection. However, due to the complex geological characteristics of shale gas reservoirs, the economic development of shale gas reservoirs is difficult. In this paper, on the basis of a full investigation of relevant literature, according to the permeability mechanism of shale gas reservoirs, the productivity of horizontal wells in low-permeability gas reservoirs is studied, and an integrated dynamic simulation model of gas reservoir wellbore is established. And the historical fitting and dynamic forecasting are carried out, and the results are in good agreement with the actual situation.

Analysis of Multiple Flow/Buildup Tests Including a 5-Year Buildup: Case Study of an Australian Shale Gas Well

Summary Long-term (multiyear) buildup tests conducted for multifractured horizontal wells (MFHWs) completed in shale reservoirs offer the unique opportunity to study and analyze flow-regimes sequences that are not commonly observed with typical buildup test periods. In this study, two buildup periods (including a rarely observed, nearly 5-year buildup), and the preceding extended flow tests, were analyzed for an MFHW completed in an Australian shale gas reservoir within the Beetaloo Basin. The objectives of the analyses were to (a) identify the sequence of flow regimes observed for each test (flow/buildup, F/BU) period; (b) extract estimates of reservoir permeability and hydraulic fracture properties; and (c) study the evolution of these properties with each subsequent test. An MFHW, the Amungee NW-1H, completed in the Velkerri B shale in Australia, was analyzed. Due to a casing deformation and inability to mill out plugs beyond this, most of the flow contribution was from the heel stages of the well. The first F/BU period was conducted from 2016 to 2021 (a nearly 5-year buildup), while the second F/BU was initiated in 2021 (buildup is currently continuing). The extended (>1 month) production tests (EPTs) preceding the buildups were analyzed using rate-transient analysis (RTA) methods [flow-regime identification/straightline /type curve analysis (TCA)] modified for shale gas properties (e.g., desorption), while the buildups were analyzed using classic pressure-transient analysis (PTA) methods. The first (~5-year) buildup period (BU 1) revealed a sequence of bilinear-linear-elliptical-pseudoradial flow followed by a second linear flow period. The first two flow regimes are interpreted to be associated with interfracture flow, while the latter is assumed to correspond to linear flow to the well. Elliptical/radial flow around fractures is rationalized to occur due to interpreted relatively short fracture half-lengths (corresponding to the high-conductivity portion of the fractures). Permeability estimates are in good agreement with diagnostic fracture injection test (DFIT) analysis. Flow-regime interpretations for the other test periods (EPTs 1 and 2, BU 2) are largely consistent, although EPT 1 flow-regime interpretation was challenged by noisy data. Permeability values derived from EPTs 1 and 2 are smaller than from buildup tests, suggesting stress sensitivity caused by drawdown. Properties derived from the analysis of BU 1 and 2 are in good agreement, suggesting that any effects caused by stress sensitivity of reservoir parameters are largely reversible. Permeability derived from all tests are much larger than those obtained from laboratory data, leading to the interpretation that natural fractures are elevating system permeability. Fracture half-lengths are also much shorter than those typically reported for MFHWs. The mostly “textbook” quality well test data obtained for this field example, combined with the length of the test periods, resulted in one of the most complete flow-regime sequences observed for an MFHW completed in a shale gas reservoir. The existence of a radial flow period observed for all test periods (interpreted to be interfracture radial flow) allows for confident estimates of reservoir permeability/skin and their evolution with each subsequent test, which is rarely reported. The radial-flow-derived permeability, combined with early linear flow analysis, also allowed fracture half-length to be estimated for all tests. This case study adds significantly to our understanding of shale gas reservoir characteristics and flow-regime sequences associated with MFHWs.

Complex Resistivity Anisotropy Response Characteristics of Wufeng-Longmaxi Formation Shale in Southern Sichuan

Electrical exploration has become an important means of shale gas reservoir exploration and evaluation, and is expected to play a key role in the later stages of reservoir fracturing and development. At present, the research on the electrical response characteristics of shale gas reservoirs and their relationship with reservoir parameters is extensive and in-depth, but there is little research on their complex resistivity anisotropy characteristics and influencing factors, which restricts petrophysical modeling and reservoir parameter prediction, and reduces the reliability of shale gas exploration and reservoir evaluation by electromagnetic methods. In this paper, shale samples from the Longmaxi Formation and the Wufeng Formation of shale gas wells in southern Sichuan were collected, the complex resistivity of 34 shales in bedding direction and vertical bedding direction were measured, and the induced polarization (IP) parameters of shales were extracted by inversion. The electrical anisotropy response characteristics under different temperature and pressure conditions were analyzed, and the influencing factors and laws of complex resistivity anisotropy of shales were revealed. Combined with the test results of shale porosity and permeability, the evaluation model of resistivity, polarizability and porosity and permeability parameters was established. The research results have formed a set of testing methods and analysis techniques for electrical anisotropy of shale reservoirs, which are mainly based on complex resistivity parameter testing. It is helpful to understand the electrical anisotropy characteristics of shale gas reservoirs in southern Sichuan; this will provide the theoretical and physical basis for shale gas reservoir evaluation and fracturing monitoring by electrical exploration.

A Technique to Determine the Breakthrough Pressure of Shale Gas Reservoir by Low-Field Nuclear Magnetic Resonance

The porous and low-permeability characteristics of a shale gas reservoir determine its high gas storage efficiency, which is manifested in the extremely high breakthrough pressure of shale. Therefore, the accurate calculation of breakthrough pressure is of great significance to the study of shale gas preservation conditions. Based on a systematic analysis of a low-field NMR experiment on marine shales of the Longmaxi Formation in the Sichuan Basin, a shale gas breakthrough pressure determination technique different from conventional methods is proposed. The conventional methods have low calculation accuracy and are a tedious and time-consuming process, while low-field NMR technique is less time-consuming and of high accuracy. Firstly, the NMR T2 spectrum of shale core sample in different states is measured through low-field NMR experiment. The NMR T2 spectra of sample in water-saturated state and dry state are combined to model the mathematical relationship between shale gas breakthrough pressure and NMR T2 spectrum. It is found that the gas breakthrough pressure is power-exponentially related to the geometric mean of NMR T2 spectrum and positively related to the proportion of micropores. Accordingly, the shale gas breakthrough pressure is quickly and accurately calculated using continuous NMR logging data and then the sealing capacity of the shale caprocks is evaluated, providing basic parameters for analyzing unconventional hydrocarbon accumulation, preservation and migration. This technique has been successfully applied with actual data to evaluate the sealing capacity of shale caprock in a shale gas well in the Sichuan Basin. It can provide a good basis for the evaluation and characterization of shale oil and gas reservoirs.

Storage Properties of the Shale Reservoir of the Lower Keluke Formation in the Shihuigou Area: Implications for the Controlling Factors

In this study, the characteristics of shale gas reservoirs of the lower part of the Keluke Formation in the Shihuigou area were investigated by using thin sections, scanning electron microscopy (SEM), and isothermal adsorption, combined with geochemical experimental analysis. Consequently, the controlling factors of the adsorption capability and gas content of the studied shale reservoir are explored. The results show that the shale reservoir space of the Keluke Formation is dominated by pores and fractures. The pores are divided into intergranular pores, intragranular pores, and dissolved pores. The pore volume of medium pores is higher than that of micropores, but the specific surface area of the medium pores is lower than that of micropores. The pore size distribution of medium pores has a feature of single peak, while the distribution of micropores is multipeaked. The results of physical properties and field gas adsorption indicate that the reservoir quality and gas content of the lower part of the Keluke Formation are good. Meanwhile, the total organic content (TOC) has a positive relationship with the methane adsorption. However, the field gas adsorption does not have a clear relationship with TOC and methane adsorption, but a positive correlation with clay mineral content. Therefore, the present study concludes that the natural gas in the shale reservoir of the lower part of the Keluke Formation is predominantly accumulated in form of free gas, and the concentration of free gas is higher than that of the adsorbed gas.

Numerical Simulation of Well Type Optimization in Tridimensional Development of Multi-Layer Shale Gas Reservoir

Aimed at the development of shale gas reservoirs with large reservoir thickness and multiple layers, this paper carried out a numerical simulation study on the optimization of three different well types: horizontal well, deviated well, and vertical well. To make the model more in line with the characteristics of shale gas reservoirs, a two-phase gas–water seepage mathematical model of shale gas reservoirs was established, considering the adsorption and desorption of shale gas, Knudsen diffusion effect, and stress sensitivity effect. The embedded discrete fracture model was used to describe hydraulic fracture and natural fracture. Based on Fortran language, a numerical simulator for multi-layer development of shale gas reservoirs was compiled, and the calculation results were compared with the actual production data of Barnett shale gas reservoirs to verify the reliability of the numerical simulator. The spread range of hydraulic fractures in the reservoir with different natural fracture densities is calculated by the simulation to determine well spacing and fracture spacing. The orthogonal experimental design method is then used to optimize the best combination of well spacing and fracture spacing for different well types. The results show that the well productivity of the high-density (0.012 m/m2) natural fractures reservoir > the well productivity of the medium-density (0.006 m/m2) natural fractures reservoir > the well productivity of the low-density (0.001 m/m2) natural fractures reservoir. According to the design of the orthogonal test, it can be seen that the most significant factor affecting the productivity of horizontal wells is the fracture spacing in the Y direction. For deviated wells and vertical wells, the X-direction well spacing has the greatest impact on its productivity.

Research on Rock Minerals and IP Response Characteristics of Shale Gas Reservoir in Sichuan Basin

As a kind of clean energy, shale gas has attracted much attention, and the exploration and development potential of shale gas resources in the middle and deep layers is huge. However, due to the changeable geological and burial conditions, complex geophysical responses are formed. Therefore, studying the characteristics of reservoir rock minerals and their complex resistivity response characteristics is helpful to deepen the understanding of the electrical characteristics of shale gas reservoirs and provide theoretical basis and physical basis for exploration and development. The study is based on shale samples from the Longmaxi Formation to the Wufeng Formation of a shale gas well in southern Sichuan, China, and the mineral composition and complex resistivity of shale are measured. Through inversion of complex resistivity model, four IP parameters, namely zero-frequency resistivity, polarizability, time constant and frequency correlation coefficient, are extracted, and the relationship between mineral components of rock samples and IP parameters is analyzed. It is found that the polarizability gradually increases and the resistivity gradually decreases with the increase in borehole depth. With the increase in pyrite content, the polarization increases and the resistivity decreases. The corresponding relational model is established, and it is found that the polarizability is highly sensitive to the characteristic mineral pyrite, which provides more effective data support for the subsequent deep shale gas exploration.

Fractal Characteristics of Deep Shales in Southern China by Small-Angle Neutron Scattering and Low-Pressure Nitrogen Adsorption

The occurrence and flow of shale gas are substantially impacted by nanopore structures. The fractal dimension provides a new way to explore the pore structures of shale reservoirs. In this study, eight deep shale samples from Longmaxi Formation to Wufeng Formation in Southern Sichuan were selected to perform a series of analysis tests, which consisted of small-angle neutron scattering, low-pressure nitrogen adsorption, XRD diffraction, and large-scale scanning electron microscopy splicing. The elements that influence the shale fractal dimension were discussed from two levels of mineral composition and pore structures, and the relationship between the mass fractal dimension and surface fractal dimension was focused on during a comparative analysis. The results revealed that the deep shale samples both had mass fractal characteristics and surface fractal characteristics. The mass fractal dimension ranged from 2.499 to 2.991, whereas the surface fractal dimension ranged from 2.814 to 2.831. The mass fractal dimension was negatively correlated with the surface fractal dimension. The mass fractal dimension and the surface fractal dimension are controlled by organic matter pores, and their development degree significantly affects the fractal dimension. The mass fractal dimension increases with the decrease of a specific surface area and pore volume and increases with the increase of the average pore diameter. The permeability and surface fractal dimension are negatively correlated, but no significant correlation exists between the permeability and mass fractal dimension, and the internal reason is the dual control effect of organic matter on shale pores. This study comprehensively analyses the mass fractal characteristics and surface fractal characteristics, which helps in a better understanding of the pore structure and development characteristics of shale gas reservoirs.

Using machine learning technology based on fuzzy neural network and geophysical data to predict the shale gas sweet spots: A case study of lower silurian longmaxi formation in Wy Block, Sichuan Basin

Compared with shale gas in north American, it is older, more mature, and significantly difference in China. Taking the Longmaxi Formation of WY block in Sichuan Basin as an example, the quantitative prediction method of sweet spots for high mature shale gas is formed. Firstly, the geophysical response characteristics of shale gas reservoir is studied, and the physical characteristics of the sweet spots are determined. Then, the distributions of reservoir evaluation parameters, such as total organic carbon, brittleness, and others, are obtained by pre-stack simultaneous inversion. Finally, fuzzy neural network method is carried out to predict the distribution of sweet spots and to deploy wells. Shale gas sweet spots in this block vertically concentrate within 30 m above the bottom of the Longmaxi Formation. And two grades of sweet spots are evaluated. The quantitative relationship between the production results of horizontal wells and the evaluation is established with Fuzzy neural network method.

Rock-Physics Template Based on Differential Diagenesis for the Characterization of Shale Gas Reservoirs

Rock-Physics Template Based on Differential Diagenesis for the Characterization of Shale Gas Reservoirs

Method to account for natural fracture induced elastic anisotropy in geomechanical characterization of shale gas reservoirs

Shale has been usually recognized as a transverse isotropic (TI) medium in conventional geomechanical log interpretation due to its laminated nature. However, when natural fractures exist in the shale rock, additional elastic anisotropy is introduced, converting laminated Shale to an orthorhombic (OB) medium. Previous studies illustrate that neglecting the natural fracture induced anisotropy in shale geomechanical log interpretation could lead to inaccurate evaluations of elastic moduli and in-situ stresses.In this paper, a new method is developed to account for the natural fracture induced anisotropy in geomechanical log interpretation based upon the TI acoustic model developed by the author and a characterization technique of elastic wave anisotropy (Sayers, 1991). The new OB model incorporates the four acoustic log data inputs and five modeling constraints in a nonlinear optimization algorithm to solve for the nine independent stiffness coefficients of an OB rock, and further to solve for the geomechanical properties and in-situ stress profiles in an OB formation.The new method was validated with a Marcellus Gas Shale field case. Both the new OB model and the conventional TI model were applied to interpret the minimum horizontal stress profile for the same formation. By comparing the results, the OB model is more robust than the TI from two aspects. First, the average stress magnitude predicted by the OB model is closer to the one measured by the Diagnostic Fracture Injection Test (DFIT). Second, the OB model predicts a more obvious stress barrier between the lower Marcellus and upper Onondaga Limestone than the TI model does. The predicted stress barrier is consistent with the observation of the microseismic events of a horizontal well drilled and completed nearby, which reveals that no hydraulic fracture propagates downward through the bottom boundary of Marcellus Shale into the underlying Onondaga Limestone.

Fractal Characteristics and Significance of Different Pore Types of the Wufeng-Longmaxi Formation, Southern Sichuan Basin, China, Based on N2 Adsorption and Image Analysis.

Shale gas is an important unconventional natural gas resource, and its reservoirs have pores with strong heterogeneity, which have an important effect on the adsorption and migration of shale gas, but the specific mechanism is still unclear. To further clarify the pore structure characteristics of shale gas reservoirs and the mechanism of their influence on CH4 adsorption capacity, marine shale samples from the Wufeng–Longmaxi formation of wells N1, N3, and N10 in Changning block, southern Sichuan Basin, China, were selected for total organic carbon (TOC), X-ray diffraction (XRD), N2 gas adsorption (N2-GA), CH4 gas adsorption (CH4-GA), and field emission scanning electron microscopy (FE-SEM). The Frenkel–Halsey–Hill (FHH) model and Slit Island Analysis (SIA) were used to calculate the fractal dimension of the pore system and different types of pores, and their relationship and influence on CH4 adsorption capacity were also discussed. The results show that the fractal dimension could reflect the complexity and heterogeneity of pores. According to the FHH model, fractal dimensions of the surface and structure of the pore system (D1 and D2, D1 < D2) were obtained, and the pore structure was more complex than the pore surface. According to SIA, the surface fractal dimensions of four types of reservoir space (DDP, DOP, DIP, and DMF) decrease progressively, and their main body is 2.60–2.80, 2.40–2.65, 2.20–2.40, and 2.05–2.30. Organic pores and intergranular pores are the most abundant, and so D1 is mainly related to DOP and DIP. In high-TOC samples, D1 is close to DOP, while in low-TOC samples, D1 is close to DIP. The complexity of the pore surface, D1, and specific surface area have a positive correlation, and with the increase of pore surface complexity, methane adsorption capacity could be significantly improved. Therefore, D1 may be used as a characterization parameter of CH4 adsorption capacity, which could provide some evidence to further clarify the adsorption mechanism of shale gas.

Characterization of shale gas reservoir of Lower Gondwana litho-assemblage at Mohuda sub-basin, Jharia Coalfield, Jharkhand, India

In quest of unconventional energy as shale gas, lower Gondwana shale-heterolith litho-assemblages of Mohuda sub-basin of Jharia Coalfield have been explored to envisage their potentiality for shale gas generation. A comprehensive approach has undertaken through measurement of in-situ gas content, petrography, rock-eval pyrolysis, proximate analysis, TOC, adsorption isotherm, SEM-EDX and XRD of selected drill core samples to establish potential shale horizons in Barren Measure and Barakar Formations. The in-situ gas content varies from 0.15 to 3.69 m 3/t with increasing depth. High palaeo-geothermal gradient in order of 5.57–6.19 °C/100 m is established where emplacement of intrusive played a dominant role. Interrelation of palaeodepth and vitrinite reflectance points to erosion of 2500 m strata in Mohuda sub-basin. Average TOC content of 9 to 17 wt% indicates excellent organic richness of source rock, while other parameters like S1, S2 and PY derived from rock-eval pyrolysis indicate fair to very good/excellent source condition for hydrocarbon generation. HI, OI, S2, TOC, VRo and Tmax values and their inter-relationships reveal Type III and Type IV kerogens coming under gas window zone of mature to post mature stage. Increase in volatile matter and fixed carbon and decrease in moisture content with depth suggest enhanced gas generation and retention capacity. Quartz dominated mineralogy in shale beds account for suitable hydrofracturing process. GIP of about 7.5 BCM of gas has been assessed and categorized depth wise and formation-wise for Raniganj, Barren Measure and Barakar formations. Experimentally calibrated adsorption isotherm data reveals favourable parameters like gas saturation level (GSL), reservoir pressure to be dropped for initiation of production (ΔP), critical desorption pressure for gas yield (PCR) and abandonment pressure (PAB) in respect of potentiality for production with an average gas recovery factor of 94.5% for all three studied shale zones, which strongly recommends the convenient reservoir characteristic for future exploitation.