Search Results (14)

Horizontal well hydraulic fracturing technology has been widely used in the efficient development of shale gas to address the challenges posed by these reservoirs’ low permeability and porosity. Despite the availability of numerous models for evaluating shale gas productivity post-fracturing, the effect of gas dynamic viscosity has been neglected. This study establishes a multiple-media and multiple-permeability coupled flow model based on the Barnett Shale and introduces Lee’s correlation for gas viscosity. The model’s feasibility and accuracy were verified by comparing the simulation results with the Barnett Shale data. The effects of reservoir damage, stimulation intensity, and fracture spacing on shale gas productivity are discussed. The results demonstrated that shale gas productivity decreased by more than 50% with intensified reservoir damage. Increasing stimulation intensity in the reservoir volume enhanced shale gas productivity. When the stimulation coefficient for the reservoir was increased from 0 to 2.5, the productivity increased by over 25%. A larger fracture spacing resulted in a smaller increase in shale gas productivity. Conversely, excessively narrow spacings significantly hindered productivity, resulting in an approximate 25% decrease. This study provides a theoretical reference for the productivity evaluation of horizontal wells in shale gas reservoirs. Full article

The viscoelastic behavior of shale reservoirs indeed impacts permeability evolution and further gas flow characteristics, which have been experimentally and numerically investigated. However, its impact on the gas depletion profile at the field scale has seldom been addressed. To compensate for this deficiency, we propose a multiscaled viscoelasticity constitutive model, and furthermore, a full reservoir deformation–fluid flow coupled model is formed under the frame of the classical triple-porosity approach. In the proposed approach, a novel friction-based creep model comprising two distinct series of parameters is developed to generate the strain–time profiles for hydraulic fracture and natural fracture systems. Specifically, an equation considering the long-term deformation of hydraulic fracture, represented by the softness of Young’s modulus, is proposed to describe the conductivity evolution of hydraulic fractures. In addition, an effective strain permeability model is employed to replicate the permeability evolution of a natural fracture system considering viscoelasticity. The coupled model was implemented and solved within the framework of COMSOL Multiphysics (Version 5.4). The proposed model was first verified using a series of gas production data collected from the Barnett shale, resulting in good fitting results. Subsequently, a numerical analysis was conducted to investigate the impacts of the newly proposed parameters on the production process. The transient creep stage significantly affects the initial permeability, and its contribution to the permeability evolution remains invariable. Conversely, the second stage controls the long-term permeability evolution, with its dominant role increasing over time. Creep deformation lowers the gas flow rate, and hydraulic fracturing plays a predominant role in the early term, as the viscoelastic behavior of the natural fracture system substantially impacts the long-term gas flow rate. A higher in situ stress and greater formation depth result in significant creep deformation and, therefore, a lower gas flow rate. This work provides a new tool for estimating long-term gas flow rates at the field scale. Full article

Gas adsorption in the porous shale matrix is critical for gas-in-place (GIP) evaluation and exploration. Adsorption investigations benefit significantly from the use of molecular simulation. However, modelling adsorption in a realistic shale topology remains a constraint, and there is a need to study the adsorption behaviour using molecular models containing both organic and inorganic nanopores. Most simulations use a single component, either kerogen (organic composition) and quartz or clay (inorganic composition), to represent the shale surface. In this work, the molecular dynamic (MD) and grand conical Monte Carlo (GCMC) simulations were utilised to provide insight into methane adsorption behaviour. Amorphous shale structures composed of kerogen and quartz were constructed. The kerogen content was varied to replicate the shale with 2 wt.% and 5 wt.% Total Organic Carbon (TOC) content with 5 nm pore size. The simulated densities of the shale structures showed consistent values with actual shale from the Montney, Antrim, and Eagle Ford formations, with 2.52 g/cm³ and 2.44 g/cm^3, respectively. The Average Error Analysis (ARE) was used to assess the applicability of the proposed amorphous shale model to replicate the laboratory adsorption isotherm measurements of actual shale. The ARE function showed that the amorphous shale shows good agreement with experimental measurements of all Barnett shale samples with an average of 5.0% error and slightly higher for the Haynesville samples with 8.0% error. The differences between the experimental adsorption measurement and simulation resulted from the amorphous packing, and actual shales have more minerals than the simulated model. Full article

Shale gas reservoirs are one of the most rapidly growing forms of natural gas worldwide. Gas production from such reservoirs is possible by using extensive and deep well fracturing to contact bulky fractions of the shale formation. In addition, the main mechanisms of the shale gas production process are the gas desorption that takes place by diffusion of gas in the shale matrix and by Darcy’s type through the fractures. This study presents a finite element model to simulate the gas flow including desorption and diffusion in shale gas reservoirs. A finite element model is used incorporated with a quadrilateral element mesh for gas pressure solution. In the presented model, the absorbed gas content is described by Langmuir’s isotherm equation. The non-linear iterative method is incorporated with the finite element technique to solve for gas property changes and pressure distribution. The model is verified against an analytical solution for methane depletion and the results show the robustness of the developed finite element model in this study. Further application of the model on the Barnett Shale field is performed. The results of this study show that the gas desorption in Barnett Shale field affects the gas flow close to the wellbore. In addition, an artificial neural network model is designed in this study based on the results of the validated finite element model and a back propagation learning algorithm to predict the well gas rates in shale reservoirs. The data created are divided into 70% for training and 30% for the testing process. The results show that the forecasting of gas rates can be achieved with an R² of 0.98 and an MSE = 0.028 using gas density, matrix permeability, fracture length, porosity, PL (Langmuir’s pressure), VL (maximum amount of the adsorbed gas (Langmuir’s volume)) and reservoir pressure as inputs. Full article

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. Full article

Shale reservoirs are the hot issue in unconventional resources. The key to the development of shale reservoirs lies in the complex fractures, which are the only path for fluid to migrate from the matrix to the wellbore in shale reservoirs. Therefore, the characteristics of shale fracture surface morphology directly affect fluid migration in shale reservoirs. However, there are few reports about the characteristics of shale fracture surface morphology as the parallel plate model was commonly used to characterize the fracture, neglecting its surface morphology characteristics and leading to great deviation. Thus, description methods were introduced to characterize shale fracture surface morphology with the aim to provide a foundation for the development of shale resources. Three shale samples were fractured by the Brazilian test, and the height distribution of the fracture surface was captured by a three-dimensional profilometer. Then, three-dimensional fracture surface morphology was regarded as a set of two-dimensional profiles, which converted three-dimensional information into two-dimensional data. Roughness, joint roughness coefficient, fractal dimension, tortuosity, and dip angle were employed to characterize shale fracture surface morphology, and their calculation methods were also, respectively, proposed. It was found that roughness, joint roughness coefficient, fractal dimension, tortuosity, and dip angle were all directional, and they varied greatly along with different directions. Roughness, joint roughness coefficient, fractal dimension, tortuosity, absolute dip angle, and overall trend dip angle were among 0.0834–0.2427 mm, 2.5715–10.9368, 2.1000–2.1364, 1.0732–1.1879, 17.7498°–24.5941°, and −3.7223°–13.3042°, respectively. Joint roughness coefficient, fractal dimension, tortuosity, and dip angle were all positively correlated with roughness. Full article

In this article, an open-source code for the simulation of fluid flow, including adsorption, transport, and indirect hydromechanical coupling in unconventional fractured reservoirs is described. The code leverages cutting-edge numerical modeling capabilities like automatic differentiation, stochastic fracture modeling, multicontinuum modeling, and discrete fracture models. In the fluid mass balance equation, specific physical mechanisms, unique to organic-rich source rocks, are included, like an adsorption isotherm, a dynamic permeability-correction function, and an Embedded Discrete Fracture Model (EDFM) with fracture-to-well connectivity. The code is validated against an industrial simulator and applied for a study of the performance of the Barnett shale reservoir, where adsorption, gas slippage, diffusion, indirect hydromechanical coupling, and propped fractures are considered. It is the first open-source code available to facilitate the modeling and production optimization of fractured shale-gas reservoirs. The modular design also facilitates rapid prototyping and demonstration of new models. This article also contains a quantitative analysis of the accuracy and limitations of EDFM for gas production simulation in unconventional fractured reservoirs. Full article

Spontaneous water imbibition plays an imperative role in the development of shale or tight oil reservoirs. Spontaneous water imbibition is helpful in the extraction of crude oil from the matrix, although it decreases the relative permeability of the hydrocarbon phase dramatically. The dynamic pore-scale network modeling of water imbibition in shale and tight reservoirs is presented in this work; pore network generation, local capillary pressure function, conductance calculation and boundary conditions for imbibition are all presented in detail in this paper. The pore network is generated based on the characteristics of Barnett shale formations, and the corresponding laboratory imbibition experiments are matched using this established dynamic pore network model. The effects of the wettability, throat aspect ratio, viscosity, shape factor, micro-fractures, etc. are all investigated in this work. Attempts are made to investigate the water imbibition mechanisms from a micro-scale perspective. According to the simulated results, wettability dominates the imbibition characteristics. Besides this, the viscous effects including viscosity, initial capillary pressure and micro-fractures increase the imbibition rate, while the final recovery factor is more controlled by the capillarity effect including the cross-area shape factor, contact angle and the average pore-throat aspect ratio. Full article

We assemble a multiscale physical model of gas production in a mudrock (shale). We then tested our model on 45 horizontal gas wells in the Barnett with 12–15 years on production. When properly used, our model may enable shale companies to gain operational insights into how to complete a particular well in a particular shale. Macrofractures, microfractures, and nanopores form a multiscale system that controls gas flow in mudrocks. Near a horizontal well, hydraulic fracturing creates fractures at many scales and increases permeability of the source rock. We model the physical properties of the fracture network embedded in the Stimulated Reservoir Volume (SRV) with a fractal of dimension $D<2$ . This fracture network interacts with the poorly connected nanopores in the organic matrix that are the source of almost all produced gas. In the practically impermeable mudrock, the known volumes of fracturing water and proppant must create an equal volume of fractures at all scales. Therefore, the surface area and the number of macrofractures created after hydrofracturing are constrained by the volume of injected water and proppant. The coupling between the fracture network and the organic matrix controls gas production from a horizontal well. The fracture permeability, $k_f$ , and the microscale source term, s, affect this coupling, thus controlling the reservoir pressure decline and mass transfer from the nanopore network to the fractures. Particular values of $k_f$ and s are determined by numerically fitting well production data with an optimization algorithm. The relationship between $k_f$ and s is somewhat hyperbolic and defines the type of fracture system created after hydrofracturing. The extremes of this relationship create two end-members of the fracture systems. A small value of the ratio $k_f/s$ causes faster production decline because of the high microscale source term, s. The effective fracture permeability is lower, but gas flow through the matrix to fractures is efficient, thus nullifying the negative effect of the smaller $k_f$ . For the high values of $k_f/s$ , production decline is slower. In summary, the fracture network permeability at the macroscale and the microscale source term control production rate of shale wells. The best quality wells have good, but not too good, macroscale connectivity. Full article

This study examined the relationship between the early production data and the long-term performance of shale gas wells, including the estimated ultimate recovery (EUR) and economics. The investigated early production data are peak gas production rate, 3-, 6-, 12-, 18-, and 24-month cumulative gas production (CGP). Based on production data analysis of 485 reservoir simulation datasets, CGP at 12 months (CGP_12m) was selected as a key input parameter to predict a long-term shale gas well’s performance in terms of the EUR and net present value (NPV) for a given well. The developed prediction models were then validated using the field production data from 164 wells which have more than 10 years of production history in Barnett Shale, USA. The validation results showed strong correlations between the predicted data and field data. This suggests that the proposed models can predict the shale gas production and economics reliably in Barnett shale area. Only a short history of production (one year) can be used to estimate the EUR and NPV of various production periods for a gas well. Moreover, the proposed prediction models are consistently applied for young wells with short production histories and lack of reservoir and hydraulic fracturing data. Full article

Total organic carbon (TOC) is an essential parameter used in unconventional shale resources evaluation. Current methods that are used for TOC estimation are based, either on conducting time-consuming laboratory experiments, or on using empirical correlations developed for specific formations. In this study, four artificial intelligence (AI) models were developed to estimate the TOC using conventional well logs of deep resistivity, gamma-ray, sonic transit time, and bulk density. These models were developed based on the Takagi-Sugeno-Kang fuzzy interference system (TSK-FIS), Mamdani fuzzy interference system (M-FIS), functional neural network (FNN), and support vector machine (SVM). Over 800 data points of the conventional well logs and core data collected from Barnett shale were used to train and test the AI models. The optimized AI models were validated using unseen data from Devonian shale. The developed AI models showed accurate predictability of TOC in both Barnett and Devonian shale. FNN model overperformed others in estimating TOC for the validation data with average absolute percentage error (AAPE) and correlation coefficient (R) of 12.02%, and 0.879, respectively, followed by M-FIS and SVM, while TSK-FIS model showed the lowest predictability of TOC, with AAPE of 15.62% and R of 0.832. All AI models overperformed Wang models, which have recently developed to evaluate the TOC for Devonian formation. Full article

We aim to replace the current industry-standard empirical forecasts of oil production from hydrofractured horizontal wells in shales with a statistically and physically robust, accurate and precise method of matching historic well performance and predicting well production for up to two more decades. Our Bakken oil forecasting method extends the previous work on predicting fieldwide gas production in the Barnett shale and merges it with our new scaling of oil production in the Bakken. We first divide the existing 14,678 horizontal oil wells in the Bakken into 12 static samples in which reservoir quality and completion technologies are similar. For each sample, we use a purely data-driven non-parametric approach to arrive at an appropriate generalized extreme value (GEV) distribution of oil production from that sample’s dynamic well cohorts with at least $1,2,3,\cdots$ years on production. From these well cohorts, we stitch together the $P_{50}$ , $P_{10}$ , and $P_{90}$ statistical well prototypes for each sample. These statistical well prototypes are conditioned by well attrition, hydrofracture deterioration, pressure interference, well interference, progress in technology, and so forth. So far, there has been no physical scaling. Now we fit the parameters of our physical scaling model to the statistical well prototypes, and obtain a smooth extrapolation of oil production that is mechanistic, and not just a decline curve. At late times, we add radial inflow from the outside. By calculating the number of potential wells per square mile of each Bakken region (core and noncore), and scheduling future drilling programs, we stack up the extended well prototypes to obtain the plausible forecasts of oil production in the Bakken. We predict that Bakken will ultimately produce 5 billion barrels of oil from the existing wells, with the possible addition of 2 and 6 billion barrels from core and noncore areas, respectively. Full article

Background: This study explores sociodemographic disparities in residential proximity to unconventional gas development (UGD) among pregnant women. Methods: We conducted a secondary analysis using data from a retrospective birth cohort of 164,658 women with a live birth or fetal death from November 2010 to 2012 in the 24-county area comprising the Barnett Shale play, in North Texas. We considered both individual- and census tract-level indicators of sociodemographic status and computed Indexes of Concentration at the Extremes (ICE) to quantify relative neighborhood-level privilege/disadvantage. We used negative binomial regression to investigate the relation between these variables and the count of active UGD wells within 0.8 km of the home during gestation. We calculated count ratios (CR) and 95% confidence intervals (CI) to describe associations. Results: There were fewer wells located near homes of women of color living in low-income areas compared to non-Hispanic white women living in more privileged neighborhoods (ICE race/ethnicity + income: CR = 0.51, 95% CI = 0.48–0.55). Conclusions: While these results highlight a potential disparity in residential proximity to UGD in the Barnett Shale, they do not provide evidence of an environmental justice (EJ) issue nor negate findings of environmental injustice in other regions. Full article

In this article we review prior literature regarding the concept of social license to operate, and related concepts, including corporate social responsibility, sustainable development, stakeholder management and cumulative effects. Informed by these concepts, we search for newspaper articles published in North American provinces and states where the Barnett, Duvernay, Marcellus and Montney shale plays are located. Using these data, we tabulate coverage of stakeholder concerns related to hydraulic fracturing and wastewater practices, and compare the extent to which these concerns vary over place and time. Our vocabulary analyses identify differences in the types and quantities of newspaper coverage devoted to concerns regarding hydraulic fracturing activities in general and wastewater practices in particular. We interpret these differences as suggesting that obtaining a social license to operate is likely not a one size fits all proposition. By understanding which stakeholder concerns are most salient in particular places and times, oil and gas operators and regulators can better tailor their strategies and policies to address local concerns. In other words, the findings from this study indicate that conventional understandings of risk as a technical or economic problem may not be adequate for dealing with unconventional resource challenges such as hydraulic fracturing. Operators and regulators may also need to manage social and cultural risks. Full article