Unconventional Shale Gas Reservoirs Research Articles

Machine learning prediction of methane, ethane, and propane solubility in pure water and electrolyte solutions: Implications for stray gas migration modeling

AbstractHydraulic fracturing is an effective technology for hydrocarbon extraction from unconventional shale and tight gas reservoirs. A potential risk of hydraulic fracturing is the upward migration of stray gas from the deep subsurface to shallow aquifers. The stray gas can dissolve in groundwater leading to chemical and biological reactions, which could negatively affect groundwater quality and contribute to atmospheric emissions. The knowledge of light hydrocarbon solubility in the aqueous environment is essential for the numerical modelling of flow and transport in the subsurface. Herein, we compiled a database containing 2129 experimental data of methane, ethane, and propane solubility in pure water and various electrolyte solutions over wide ranges of operating temperature and pressure. Two machine learning algorithms, namely regression tree (RT) and boosted regression tree (BRT) tuned with a Bayesian optimization algorithm (BO) were employed to determine the solubility of gases. The predictions were compared with the experimental data as well as four well-established thermodynamic models. Our analysis shows that the BRT-BO is sufficiently accurate, and the predicted values agree well with those obtained from the thermodynamic models. The coefficient of determination (R2) between experimental and predicted values is 0.99 and the mean squared error (MSE) is 9.97 × 10−8. The leverage statistical approach further confirmed the validity of the model developed.

Geochemical and mineralogical characterizations of Silurian “Hot” shales: Implications for shale gas/oil reservoir potential in Jeffara basin-southeastern Tunisia, North Africa

The Silurian organic-rich hot shale deposits represent the origin of 80–90% Paleozoic sourced hydrocarbons on the entire Saharan Platform. As such, it is an area of significant interest for exploring its potential as an unconventional reservoir and gaining new insights into its properties. In this study, the geochemical and mineralogical analysis of eighty-two borehole samples from three studied wells (T, B, and M) located in Jeffara Basin, in southeastern Tunisa, distributed over a depth between 1200 m and 2200 m, show that the hot shale layer has significant potentials of an unconventional shale gas reservoir. According to the rock-eval and GCMS results, the total organic carbon (TOC) of the hot shale deposits is good to great, ranging between 0.54 wt% and 23.86 wt%, and the average hydrogen index (HI) is around ∼200 mg HC/g of TOC, which indicates that the hot shales were originally rich in type II/III organic matter (OM). The thermal maturity of the preserved OM is determined by the kerogen type with values varying from 0.4% to 1%, and Tmax values reaching 460 °C in T, B, and M wells which indicate that the hot shales preserved early mature to mature OM placed within oil/gas generation window. The calculated geochemical parameters reveal an average hydrocarbon generation potential (HGP) for the three studied wells of 20.37 kg HC/ton rock. In addition, the transformation ratios (TR) in T, B, and M wells are, respectively, 21.12%, 30% and 35.25%. However, only B and M wells show a cross-over layer, with oil saturation index (OSI) exceeding 100%, with significant potential as a hydrocarbon saturated source rock, making it a considerable target for unconventional oil exploration. Relevant results of Rock-Eval, biomarkers and XRD exhibit coherent features that reflect reducing marine conditions during the lower Silurian period. Moreover, the mineralogical composition was investigated to estimate the importance of frackable mineral fractions such as quartz (∼15%) and carbonates (calcite-dolomite). Mineral brittleness index (MBI) was calculated and compared to a well-known unconventional reservoir in the Neal shale member of the Floyd shale group in the Black Warrior Basin (US), which displays moderate to low MBI. The hot shales in the study area have a considerable MBI, which could be easily enhanced by hydraulic fracturing to liberate oil/gas from the potentially saturated unconventional shale reservoir.

Chemical and Carbon Isotope Composition Proves Effective as Gas Diagnostic Tool

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209992, “Gas Chemical and Carbon Isotope Composition as a Diagnostic Tool for Energy,” by Zainab Almubarak, SPE, Mohammad Alrowaie, and Feng Lu, Saudi Aramco, et al. The paper has not been peer reviewed. _ Chemical and carbon isotopic compositions of produced gases are useful tools to monitor gas production and to assess their origin, thermal maturity, and migration. In the complete paper, the authors present different geochemical approaches to assess the origin of gases and thermal maturity and to evaluate the effect of adsorption on shale gas during production. Introduction Carbon isotope type curves constructed for compounds from methane through n-pentane can be used to group gases into distinct families and correlate them to their source rocks. Large variations in carbon isotope ratios exist among the natural gas compounds, which are caused by isotopic fractionation between the sedimentary organic matter (kerogen) and each individual hydrocarbon compound. During the generation of hydrocarbons from kerogen, cracking of 12C-12C bonds requires slightly less energy than 13C-12C bonds. Thus, hydrocarbons will be enriched in 12C relative to the kerogen. Methane, which contains only one carbon atom, shows the greatest fractionation and will have the most negative δ13C value (most enriched in 12C). Ethane through pentane show progressively less fractionation (less negative δ13C values), with the latter usually having a δ13C value close to that of kerogen (and associated oil). The magnitude of the fractionation effect will vary depending on the type of kerogen (i.e., Type I, II, IIS, or III), the temperature during hydrocarbon generation, and the adsorption/desorption effect. Thus, gases generated from different source rocks often have distinctive carbon isotope type curves. In shale gas (unconventional reservoirs), two different types of gases coexist—free gas and adsorbed gas. Free gas occurs in natural fractures and matrix pores, whereas adsorbed gas is noted on the surface of pores. During the early stages of production, free gas accounts for most produced gas. The adsorbed gas starts in mid-late stages but maintains high and stable production. In this study, the authors use carbon isotopic compositions of light hydrocarbons (C1–C5) to assess origin and thermal maturity and to compare different gases derived from unconventional reservoirs. Moreover, carbon isotopes are used to assess migration paths and to monitor gas production in unconventional shale gas reservoirs. The gas samples were collected periodically from the same interval to monitor any isotope variation and evaluate the effect of gas adsorption. Methods Pressurized samples of natural gas were collected from conventional and unconventional reservoirs through production tests, drillstem tests, or downhole samplers and analyzed for chemical composition. For the conventional study, a total of 13 gas samples were collected from different reservoirs (A, B, C, D, and J): four gas samples from Reservoir A, two gas samples from Reservoir B, three gas samples from Reservoir C, three gas samples from Reservoir D, and one gas sample from Reservoir J. Gases derived from Reservoirs A, B, and J are younger and shallower than gases derived from Reservoirs C and D (older and deeper). For the unconventional study, seven gas samples were collected periodically from the same shale interval (Reservoir W) from the same well (Well Y) on different dates to monitor any isotope variation.

Geomechanical risk and mechanism analysis of CO2 sequestration in unconventional coal seams and shale gas reservoirs

With global greenhouse gas emissions hitting record highs in 2021, CO2 geological sequestration (CGS) is the most realistic and feasible technology to ensure large-scale carbon reduction to achieve global carbon capping and carbon neutrality goals. Both coalbed methane and shale gas have the characteristics of self-generation and self-storage, which is considered to be a valuable target reservoir for geological sequestration of CO2. After a high volume of CO2 is injected into unconventional coal seams and shale gas reservoirs, many geomechanical issues may be induced, resulting in leakage. Therefore, it is crucial to evaluate the geomechanical risks of CO2 geological sequestration. In this article, global CO2 emissions and geological resources available for sequestration are teased out. The effects of coupled CO2-water-rock-driven geomechanical, geophysical, and geochemical interactions on the evolution of rock physical properties and pore characteristics, as well as caprock sealing, are discussed. The caprock failure and its inducing mechanism are analyzed, and the criteria for predicting the occurrence of risk are summarized, which is necessary for pressure management and risk prevention. To serve as a benchmark for CO2 sequestration in unconventional coal seams and shale gas reservoirs.

Unconventional shale gas potential of lower visean organic-rich formations in Glynsko-Solohivskyi petroleum region

Exploration of unconventional gas resources in Ukraine is highly relevant and important for achievement energy independence of Ukraine and Europe. Production of current oil & gas fields and alternative energy resources are not able to cover our needs nowadays. Now we can not fully fill these gaps by energy resources. In this article geological environments, age, mineralogy composition and maturity of unconventional shale and carbonate gas reservoirs of Lower Visean in one of the biggest field of Dnipro-Donets Basin (DDB) were studied. The hydrocarbon potential of two main target horizons V-23 and V-24-25 by using integrated approach of analyzing available core analysis data were performed. The results of the geochemical analysis show that the maturity level of shale of the Rudov beds (V-23) appear in oil window (Ro~0.8%) which can generate oil in the early mature phase. Visean carbonates (V-24-25) have the similar level of maturity - (Ro~0.77%). Target rocks are characterized by high total organic content (TOC): average values vary from 2% for organic-rich carbonates to 5.6% for shales which indicates relatively good to excellent source rock generative potential. According to X-ray diffraction analyses (XRD) of black shale formation domination of silica minerals (54.6%), calcite and clays (25.6%) with minor amounts of albite, feldspar and pyrite were observed. Carbonate platform V-24-25 logically is characterized by much higher calcite content of 52.2 % with low amount of dolomite – 5.5%. Quite high quartz content is also observed – average value is of about 30.7%. Clay minerals are not identified in every sample, but average values are of about 18.9%, pyrite content – 6.8%. It shows that Visean target formation of Glynsko-Solohivsky Petroleum region is characterized by anoxic environment. This data verified that V-23 and V-24-25 horizons are the brittle formations and favorable for multistage fracking. Thin section analysis confirms our results from mineralogical point of view. The presence of fractures in core samples is additional indicator for hydraulic fracturing and producing gas from such unconventional reservoirs. As a conclusion, the Lower Visean organic-rich formations V-23 and V-24-25 from Glynsko-Solohivsky Petroleum region are mature, are characterized by a high content of organic carbon, have enough thickness (30-120 m) and large areal extent. They should be regarded as a potential shale gas target.

Simplified scaling relations for the depth-dependence and IFT reduction of fluid imbibition in gas-saturated reservoir rocks

Imbibition of water into fractured unconventional reservoirs is a significant factor contributing to the large volumes of permanently lost water by hydraulic fracturing. The lost water partitions at the fracture-matrix interface thereby restricting gas flow into the fractures. Thus, minimizing the large water footprint during the fracturing process is very attractive for water conservation and gas production. A key step towards achieving this goal is quantifying uncertainties needed to reliably predict water imbibition and to evaluate the success of efforts aimed at minimizing it. In this contribution, we present new scaling relations for water imbibition in gas-saturated rocks that account for the depth-dependence of fluid properties and chemical alteration of IFT through the use of a surfactant. We then propose a new method for quantifying uncertainties relating to rock properties, two-phase fluid properties, and the driving force for imbibition. We applied the proposed approach to analyze glass-bead pack and shale experiments involving water imbibition into air-filled pores, and validated our model predictions against published values from X-ray CT images and transient permeability measurements. Our work provides a methodology for quantifying the uncertainties pertaining to water imbibition, thereby enabling optimization of post-fracturing interventions aimed at minimizing water loss in deep unconventional shale gas reservoirs.

Oxidation treatment of shale gas produced water: Molecular changes in dissolved organic matter composition and toxicity evaluation

Produced water (PW) is the largest waste stream generated by hydraulic fracturing in an unconventional shale gas reservoir. Oxidation processes (OPs) are frequently used as advanced treatment method in highly complicated water matrix treatments. However, the degradation efficiency is the main focus of research, organic compounds and their toxicity have not been properly explored. Here, we obtained the characterization and transformation of dissolved organic matters of PW samples from the first shale gas field of China by two selected OPs using FT-ICR MS. CHO, CHON, CHOS, and CHONS heterocyclic compounds associated with lignins/CRAM-like, aliphatic/proteins, and carbohydrates compounds were the major organic compounds identified. Electrochemical Fe2+/HClO oxidation preferentially removed aromatic structures, unsaturated hydrocarbons, and tannin compounds with a double-bond equivalence (DBE) value below 7 to more saturated compounds. Nevertheless, Fe (VI) degradation manifested in CHOS compounds with low DBE values, especially single bond compounds. Oxygen- and Sulfur-containing substances, primarily O4–11, S1O3-S1O12, N1S1O4, and N2S1O10 classes, were the main recalcitrant components in OPs. The toxicity assessment showed that the free-radical-formed Fe2+/HClO oxidation could cause significant DNA damage. Therefore, the toxicity response byproducts need spcial attention when conducting OPs. Our results led to discussions on designing appropriate treatment strategies and the development of PW discharge or reuse standards.

Parallel fully implicit chemical potential-based modeling of unconventional shale gas reservoirs

The design of novel mathematical models and state-of-the-art simulators for unconventional shale gas reservoirs plays an increasingly important role in the current energy mix of the world’s growing energy demand. In this paper, we present a robust and scalable framework, which is based on the chemical potential-based modeling and the fully implicit method (FIM), to model and simulate this highly nonlinear flow transport problem on a large scale. In the proposed approach, a thermodynamically consistent mathematical model of gas flow in shale formations, which employs the gas density and the chemical potential gradient, is developed to satisfy the second law of thermodynamics and meanwhile guarantee the energy dissipation property. And then the family of fully implicit finite element algorithms is utilized to accurately capture the complicated flow physics behind the transport process in shale media on high resolution grids. In particular, our approach further enhances the numerical formulation by proposing the family of Newton–Krylov methods for efficiently computing, and the parallel implementation of the simulator is achieved by using the domain decomposition technique. Numerical experiments are presented to demonstrate the robustness and parallel scalability of the solution strategies for several interesting shale gas flow problems in two or three dimensions. With the proposed parallel method, large-scale reservoir simulation can be obtained on the Shaheen-II supercomputer with up to 40960 processors, which enables to achieve a good strong scalability by saving more than 90 percent of computing time, when the problem size is enlarged to hundreds of millions of degrees of freedom.

Characterizing Microearthquakes Induced by Hydraulic Fracturing With Hybrid Borehole DAS and Three-Component Geophone Data

Fluids injected during hydraulic fracturing (fracking) in unconventional shale oil and gas reservoirs, geothermal system enhancement, wastewater disposal, and carbon capture and storage can induce microearthquakes. The spatiotemporal distribution of induced earthquakes is often used to trace the growth of fractures in target layers and guides production. We analyze microseismicity behavior induced by fracking in the Montney Formation, one of the largest unconventional oil and gas reservoirs in North America. An optical fiber deployed in a horizontal well provides extensive spatial sampling and data coverage for microseismic imaging. We design median and F-k filters to predict instrumental and random noise and further suppress them by adaptive noise subtraction. An elliptical vertical transverse isotropic (VTI) velocity model is derived from the Backus-averaged well-log sonic data and is modified to match the microseismic wavefronts by a grid search. We image 41 previously cataloged microearthquakes recorded by DAS using Geometric-mean Reverse Time Migration. We find that the fiber geometry’s lack of 2D/3D variations increases the non-uniqueness of the image point location, and the P-wave particle motions derived from 3C geophones data can effectively eliminate the location ambiguity. The spatiotemporal distribution of our updated locations agrees with the fracking schedule. Predicted P- and S-wave traveltimes from the updated locations also match with the observed waveforms. Analyzing data sensitivity to source locations confirms the potential limitations imposed on source imaging by the geometry of borehole observations and shows that relocation accuracy is directionally dependent. We also investigate the feasibility of estimating source focal mechanisms using realistic DAS and geophone observations. Our study provides guidance for characterizing microearthquake sources and optimizing observation geometry for unconventional reservoirs.

Hierarchical Surrogate-Assisted Evolutionary Algorithm for Integrated Multi-Objective Optimization of Well Placement and Hydraulic Fracture Parameters in Unconventional Shale Gas Reservoir

Integrated optimization of well placement and hydraulic fracture parameters in naturally fractured shale gas reservoirs is of significance to enhance unconventional hydrocarbon energy resources in the oil and gas industry. However, the optimization task usually presents intensive computation-cost due to numerous high-fidelity model simulations, particularly for field-scale application. We present an efficient multi-objective optimization framework supported by a novel hierarchical surrogate-assisted evolutionary algorithm and multi-fidelity modeling technology. In the proposed framework, both the net present value (NPV) and cumulative gas production (CGP) are regarded as the bi-objective functions that need to be optimized. The hierarchical surrogate-assisted evolutionary algorithm employs a novel multi-fidelity particle-swarm optimization of a global–local hybridization searching strategy where the low-fidelity surrogate model is capable of exploring the populations globally, while the high-fidelity models update the current populations and thus generate the next generations locally. The multi-layer perception is chosen as a surrogate model in this study. The performance of our proposed hierarchical surrogate-assisted global optimization approach is verified to optimize the well placement and hydraulic fracture parameters on a hydraulically fractured shale gas reservoir. The proposed surrogate model can obtain both the NPV and CPG with satisfactory accuracy with only 500 training samples. The surrogate model significantly contributes to the convergent performance of multi-objective optimization algorithm.

Data-driven model predictive control for closed-loop refracturing design and optimization in naturally fractured shale gas reservoir under geological uncertainty

The reliable and predictive control for closed-loop refracturing design and optimization is of significance to improve the unconventional resource development and recovery in petroleum engineering. To reduce refracturing-decision risk under uncertainty for unconventional shale gas reservoir, we present an efficient and robust two-stage refracturing optimization workflow through hybridizing data-space inversion and non-dominated sorting genetic algorithm-II. Without performing history matching step, we adapt data-space inversion to simultaneously predict post-history pressure field and shale gas production corresponding to specific refracturing parameters given history measurement. In the proposed framework, both the enhanced net present value and enhanced cumulative gas production after refracturing stimulation are regarded as the bi-objective functions while the refracturing parameters including fracture number and fracture half-length are chosen as the decision variables. The proposed two-stage refracturing optimization strategy enables us to effectively identify the potential candidate clusters and/or wells and then search the optimal refracturing parameters efficiently and reasonably.

Estimation of in situ stresses from PP-wave azimuthal seismic data in fracture-induced anisotropic media

Horizontally transverse isotropy (HTI) induced by vertical or subvertical aligned fractures is common for unconventional fractured porous shale oil or gas reservoirs. Compared with the unfractured rocks, the seismic response characteristics of PP-wave azimuthal amplitudes are usually disturbed by the fractures and the in situ stresses. Knowledge of fracture properties, as well as in situ stresses, is required to optimize horizontal well planning and hydraulic fracturing during production, and the seismic inversion for in situ stresses from the PP-wave azimuthal amplitude data in fracture-induced anisotropic media is an essential step. Using the linear-slip theory and the effective stress law, we derive the fluid-saturated effective elastic stiffness tensors parameterized by background elastic moduli, the effective stress coefficient of isotropic host rocks, fluid modulus, porosity, and fracture parameters based on the anisotropic Gassmann’s fluid substitution equation. Combining the perturbations in saturated stiffness tensors and scattering theory, we formulate the reflection coefficient equation of PP-wave data as a function of background porosity-related stress parameter and two (i.e., normal and shear) fracture weakness parameters. Following Bayes’ rule, we estimate the porosity-related stress parameter and fracture weaknesses using the inversion method of azimuthal Fourier coefficients. Finally, we compute the effective horizontal and vertical in situ stresses using the estimated elastic moduli, porosity-related stress parameter, and fracture weaknesses. Synthetic and real data sets demonstrate that our proposed inversion approach based on the derived reflection equation provides us another way to obtain reasonable estimates of in situ stresses in a complex-fractured porous shale reservoir.

Machine-learning-based well production prediction under geological and hydraulic fracture parameters uncertainty for unconventional shale gas reservoirs

Shale gas production prediction under history-matching-based geomodel is crucial to achieve reliable assessment and economic management of unconventional shale resources, however, conventional history matching is generally performed through repeatedly running high-fidelity reservoir simulations and therefore presents intensive computation-cost in practical applications. Without the need of history matching step, this work presents an efficient and robust post-history production forecasting framework using a latent-space learning-based direct forecast approach, e.g., referred to as LS-LDFA. A novel dimensionality reduction method, e.g., convolutional autoencoder, is employed to regularize the multi-well time-series data by low-order representation within a latent space. Once the machine-learning proxy is trained offline, the online post-history production forecast can be efficiently achieved by input history data. This paper presents some comparative studies between LS-LDFA and model-based history matching. This approach is tested on two examples with an increasing complexity, e.g., a multi-fractured horizontal well and a naturally fractured reservoir model with multi-well-pad-production based on synthetic shale formation. The results confirm that the method achieves high robustness and computational efficiency simultaneously in comparison with the conventional history matching. The application of learning-based direct forecast approach can effectively fuse information from history data and thus support reliable decision-making and risk assessment.

Two-Stage Differential Hydrocarbon Enrichment Mode of Maokou Formation in Southeastern Sichuan Basin, Southwestern China

Abstract Sichuan Basin is one of the most potential areas for natural gas exploration and development in China. The Maokou Formation in the basin is one of the important gas-bearing layers in southeastern Sichuan. In recent years, several exploration wells have obtained industrial gas flow in the first member of the Middle Permian Maokou Formation (hereinafter referred to as the Permian Mao-1 member of Maokou Formation), revealing that it may become a new field of oil and gas exploration in Sichuan Basin. Drilling and field survey results show that the shale of Maokou Formation in southeastern Sichuan contains eyeball-shaped limestone. Early studies suggest that the Permian Mao-1 member of Maokou Formation in Sichuan Basin is a set of high-quality carbonate source rocks, but ignoring its oil and gas exploration potential as an unconventional shale reservoir similar to the shale. The enrichment regularity of unconventional natural gas has not been studied from the perspective of source-internal accumulation. And there is a lack of analysis of oil and gas enrichment mode. In this study, we took the Permian Mao-1 member of Maokou Formation in southeastern Sichuan as the target layer. Through macroscopic outcrop observation and geochemical analysis and based on unconventional oil and gas enrichment theory, we carried out a study on natural gas enrichment mode of eyeball-shaped limestone of the Permian Mao-1 member of Maokou Formation in Sichuan Basin. The results show that the hydrocarbon enrichment pattern of the Maokou Formation in southeastern Sichuan is different from the accumulation and occurrence process of common unconventional shale gas reservoirs and conventional carbonate reservoirs. It is a special new hydrocarbon accumulation mode between the above two. According to the difference in the charging time of the hydrocarbon, the background of the reservoiring dynamics, and the occurrence state of oil and gas, we divide the two-stage differential enrichment mode of oil and gas, that is, “early intralayer near-source enrichment” and “late interlayer pressure relief adjustment.”

The Effects of Physical and Geometrical Properties on Rock Brittleness Index Based on Numerical Modeling

Rock brittleness is a key parameter to quantify and evaluate the brittle nature of the rock. A better estimating technique of rock brittleness is crucial for acquiring an efficient stimulation of unconventional shale gas reservoirs such as hydraulic fracturing. One way to predict rock brittleness index is by using rock elastic moduli. These physical properties highly depend on the complexity of the microstructure, fluid content, and mineral composition. The other way is by measuring the rock mineral composition itself. This complexity of the microstructure can be accurately characterized by using imaging techniques such as micro-CT scans. This study used the finite element method to estimate rock brittleness index based on elastic properties on synthetic and digital rock images. We then evaluate the effect of physical and geometrical properties (pore aspect ratio, water saturation, and mineral composition) in determining the rock brittleness characteristic. The results indicate that there is an increase in Young’s modulus along with an increasing pore aspect ratio to 1, which in turn raises the rock brittleness. Fluid saturation, in this case, water saturation, causes brittleness to be increased. The rock mineral composition, such as abundant quartz and carbonate content, yields high brittleness values, while high clay content and porosity lower the rock brittleness. Overall, the results imply that pore geometry, fluid saturation, and mineral composition significantly alter the rock strength parameters.

First principle elastic property study of α-AI2O3 for application as nano-proppants

Slickwater hydraulic fracturing creates complex fracture networks in unconventional shale gas reservoirs. The use of spherical micron and nano-sized particles have been proposed as suitable sized materials to keep nano fractures conductive. Few materials have been investigated for occupying induced unpropped nano fractures. In this study, the nanomechanical properties of α-Al2O3, a commonly used fracture fluid nanomaterial is calculated using the density functional theory to study its pressure-dependent elasticity and hardness. The elastic properties of α-Al2O3 are calculated within the CASTEP code under different hydrostatic pressures between 0 and 1 GPa. α-Al2O3 experienced a 0.11% and 0.34% in structural lattice constant and volume, respectively. Material mechanical properties such as the Bulk modulus B, decrease Shear modulus G, Young’s modulus and Poisson’s ratio of the trigonal α-Al2O3 nanocrystal structure are derived through the Voight-Reus-Hill approximation scheme. Young’s modulus of 391.8 and Hardness of 20.4 Gpa show that α-Al2O3 nanoparticles can withstand reservoir pressures without significant deformation. Elastic constants of α-Al2O3 generally increased with high pressure. However slight variations occurred in the derived nanomechanical properties between the pressure regime investigated.

Diagenesis and Its Impact on the Reservoir Quality of Continental Shales: A Case Study of the Lower Jurassic Da’anzhai Member of the Ziliujing Formation in the Sichuan Basin, China

The Jurassic continental shale oil (gas) is a favorable unconventional resource in the Sichuan Basin of China. In this paper, analysis methods such as core and outcrops observation, thin section identification, scanning electron microscopy (SEM), and X-ray diffraction (XRD) are used to describe the characteristics of lacustrine fine-grained rock reservoir in Da’anzhai Member of the Ziliujing Formation in Sichuan Basin, and it discussed the influence and control of lacustrine fine-grained rock diagenesis on the quality of the reservoir, in order to determine the shale reservoir control factors. The results show that there are three types of rocks in the Da’anzhai Member, which are mudstone, siltstone, and limestone, and the rock combination of shell shale intercalated with shell limestone is developed in the Da 2 submember. Fine-grained sedimentary rocks in this section have undergone compaction, cementation, dissolution, metasomatism, transformation of clay minerals, and hydrocarbon generation of organic matter, which are currently in the middle diagenetic stage A or B substage. Compaction and cementation are the main factors that control the physical use of shale and limestone, and strong cementation is the main reason for the tightness of limestone reservoirs in the Da’anzhai Member in the northern and eastern parts of Sichuan Basin. The difference between dissolution and cementation is the main control factor for the formation of limestone or argillaceous limestone reservoirs in the same section in central Sichuan Basin. The organic-rich shale and shell shale of the Yuanba and Fuling area are the most favorable reservoirs of the Ziliujing Formation in this region. The shell limestone that experienced favorable dissolution in the Da’anzhai Member in the central of the Sichuan Basin has become a limestone reservoir. Discussing the impact of continental fine-grained rock diagenesis on the reservoir can better explore and develop similar intervals, enrich unconventional shale oil and gas accumulation and storage theories, and provide basic theoretical support for finding favorable unconventional shale oil and gas reservoirs.

Data-driven machine learning approach to predict mineralogy of organic-rich shales: An example from Qusaiba Shale, Rub’ al Khali Basin, Saudi Arabia

The Qusaiba Shale is a proven source rock for the Palaeozoic petroleum system of the middle east and it is targeted as a potential source of unconventional shale gas potential reservoirs in Saudi Arabia and recently considered a possible source of unconventional gas. Mineralogy of shale plays a key role in the successful design and performing the hydraulic fracturing operations and in turn evaluating the production potential. There is limited research available in the literature on the application of artificial intelligence for mineralogical prediction, which motivate us to perform this research on the Qusaiba Shale. The study aims to predict the Qusaiba Shale mineralogy, specifically clay and quartz minerals using readily available conventional logs, where both minerals are the major constituents of shale and help in assessing the brittle and ductile zones within the shale formation. Three lithofacies were defined in the Qusaiba Shale based on different geological and sedimentary features of core samples, and they have different ranges of quartz and clay content. Predictive models were developed for two utmost important minerals present in Qusaiba Shale formation including clay and quartz using artificial intelligence techniques. An adaptive neuro-fuzzy inference system (ANFIS) and artificial neural networks (ANN) were employed to precisely predict the two major minerals contents in Qusaiba Shale formation. All four models were found to have good accuracy. ANN-based models exhibited minimal errors with AAPE and RMSE of 2.53 and 1.45 for quartz and 3.43 and 2.01 for unseen data points for clay prediction models respectively. ANFIS-based prediction models presenting the AAPE and RMSE 2.67 and 1.83 for predicted quartz values and 3.59 and 1.89 for the clay content respectively. The applied artificial intelligence predictive model for major minerals in Qusaiba Shale i.e., clay and quartz would be a viable and useful approach to achieve valuable information about minerals content in shale for prospective evaluation of shale gas reservoirs. The results of this work would be useful in prospect evaluation and optimizing the production from unconventional shale gas reservoirs in Saudi Arabia. Moreover, the approach used may provide insights into replacing traditional mineralogy determination methods to save cost and resources in the absence of cores and mineralogy logs in the unconventional Qusaiba Shale resource. Furthermore, applying the same artificial intelligence approach and steps could be used for the field development of other shale gas and oil fields worldwide.

Deformation Rate Analysis: How to determine in-situ stresses in unconventional gas reservoirs

Magnitude and direction of in-situ stresses are crucial inputs of any geomechanical analysis when it comes to the stability of structures under different downhole conditions . There have been many approaches proposed to determine these parameters on the laboratory or field scales, but many presumptions, complications and difficulties are often involved. Deformation Rate Analysis (DRA) is one of these approaches proposed to determine the magnitude of in-situ stresses based on the Kaiser effect in the applications concerning near surface conditions. In this paper attempts are made to show the application of the DRA in determination of in-situ stress for unconventional shale gas reservoirs. A case study from the Perth basin in Australia was considered to examine the accuracy of the results on the field scale. It was found that compliant shale samples may not be able to provide a good estimation of in-situ stresses, but the DRA appears to be an effective method of in-situ stress determination for unconventional shale gas reservoirs. The elapsed time between the sample extraction and testing also plays an important role during the laboratory measurements while the impact of the loading cycle on the strength of the samples should not be ignored.

Multi-scale modelling of gas transport and production evaluation in shale reservoir considering crisscrossing fractures

Advancements in recent shale gas development technologies like creating hydraulic fracturing have greatly improved the production of unconventional shale gas reservoirs (USGR). However, the production of USGR is still low mainly due to the inefficient gas transport in tight shale formation. Towards this end, the investigations about the mechanism of gas transport through the fractures and the effects of both hydraulic and natural fractures on the overall gas production are urgently needed. In this study, a multi-scale modelling is established to analyze the gas transport and production performance in shale formation with crisscrossing natural fractures using finite element method (FEM). For the base case with fracture-scale model, the gas transport behavior and pressure distribution within the matrix and crisscrossing fractures are revealed, demonstrating that the crisscrossing fractures serve as the fast paths to enhance the gas transport from shale matrix to wells. Then, the field-scale model is developed by considering the complex fracture networks consisting of the hydraulically fractured horizontal wells and crisscrossing natural fractures, which is well verified against field data. On this basis, the comprehensive analysis for the influence of various parameters, including the properties of matrix, hydraulic fractures and natural fractures, on the production performance are conducted to optimize the exploitation strategy of shale gas reservoir. It is believed that the multi-scale simulation framework and the optimized exploitation strategies presented in this study are useful for the enhanced gas recovery (EGR) of shale reservoir.