Unconventional Reservoir Simulation Research Articles

Field Application of a Novel Multiresolution Multiwell Unconventional Reservoir Simulation: History Matching and Parameter Identification

Summary This study focuses on developing an efficient workflow by integrating a multiresolution simulation model and a multiobjective evolutionary algorithm (MOEA) for application to multiwell unconventional reservoirs. In this approach, hydraulic fractures are represented using a dual porosity, dual permeability system facilitated by an embedded discrete fracture model (EDFM). A novel fast-marching simulation method is used to cut down on computational expenses by an order of magnitude, greatly accelerating the history-matching process. A variety of integrated monitoring technologies were implemented to map out the hydraulic fracture network. Insights into hydraulic fracture locations were gleaned from warm-back analysis of distributed temperature sensing data, and these locations were then assimilated into the simulation model as embedded discrete fractures. For the simulation, a fast-marching-based multiresolution model was used to partition the reservoir into local and shared domains guided by the diffusive-time-of-flight (DTOF) principle. The local domain maintained the original 3D grids near the wells while transforming the remaining area into 1D grids to accelerate the simulation process. Before history matching, a thorough sensitivity analysis was conducted to pinpoint the most impactful parameters. Subsequently, the model was fine-tuned using production data through an MOEA. The most sensitive parameters in history matching were identified as fracture geometry and conductivity, fluid saturations, and rock compressibility in the stimulated reservoir volume (SRV) areas. After history matching, there was a noteworthy reduction in the uncertainty of these tuning parameters. The calibrated parameters are valuable to evaluate the effectiveness of the well completion design. Overall, this work emphasizes the innovative combination of techniques applied, the efficiency gains in the history-matching process, and the scalability of the approach to other oilfield applications.

Rapid Simulation of Unconventional Reservoirs by Multidomain Multiresolution Modeling Based on the Diffusive Time of Flight

Summary The fast marching method (FMM)-based rapid flow simulation has been shown to accelerate simulation efficiency by orders of magnitude by transforming 3D simulation to equivalent 1D simulation using the concept of the “diffusive time of flight” (DTOF). However, the 1D transformation does not directly apply to multiwell problems. In this paper, we propose a novel DTOF-based multidomain multiresolution discretization scheme to accelerate multiwell simulation of unconventional reservoirs. Our method formulates multiwell simulation problems based on the DTOF which displays the pressure front propagation in unconventional reservoirs. The DTOF contours are used to partition the reservoir into local and shared domains. A local domain is where the flow is dominated by a single well, and the shared domain is where the fluid flow is influenced by multiple wells. The DTOF contours expand independently in local domains and interfere in the shared domain. After the partitioning, each domain is discretized using a multiresolution scheme whereby the original 3D fine mesh is preserved near the wells to account for detailed physics including gravity, and the rest of the domain is discretized into 1D mesh based on the DTOF contours to alleviate the simulation workload. The power and efficacy of our approach are demonstrated using synthetic and field-scale simulation models with different degrees of geologic and well-completion complexity. The simulation results, number of active cells, and computation time for the proposed discretization scheme are compared with the original high-fidelity 3D model for each case. The results show that the proposed method is suitable for multiwell simulation problems in unconventional reservoirs and can accelerate flow simulations by orders of magnitude with minimal loss of accuracy. The novelty of this work is the creation of DTOF-derived multiresolution discretization with local and shared domains to simplify and accelerate the calculation of subsurface flow problems, especially in unconventional reservoirs. Our workflow can be easily interfaced with commercial simulators, making it suitable for large-scale field applications.

Phase Behavior and Composition Distribution of Multiphase Hydrocarbon Binary Mixtures in Heterogeneous Nanopores: A Molecular Dynamics Simulation Study.

In this study, molecular dynamics (MD) simulation is used to investigate the phase behavior and composition distribution of an ethane/heptane binary mixture in heterogeneous oil-wet graphite nanopores with pore size distribution. The pore network system consists of two different setups of connected bulk and a 5-nm pore in the middle; and the bulk connected to 5-nm and 2-nm pores. Our results show that nanopore confinement influences the phase equilibrium of the multicomponent hydrocarbon mixtures and this effect is stronger for smaller pores. We recognized multiple adsorbed layers of hydrocarbon molecules near the pore surface. However, for smaller pores, adsorption is dominant so that, for the 2-nm pore, most of the hydrocarbon molecules are in the adsorbed phase. The MD simulation results revealed that the overall composition of the hydrocarbon mixture is a function of pore size. This has major implications for macro-scale unconventional reservoir simulation, as it suggests that heterogenous shale nanopores would host fluids with different compositions depending on the pore size. The results of this paper suggest that modifications should be made to the calculation of overall composition of reservoir fluids in shale nanopores, as using only one overall composition for the entire heterogenous reservoir can result in significant error in recovery estimations.

Shale Poroelastic Effects on Well Performance Analysis of Shale Gas Reservoirs

The effect of poroelastic properties of the shale matrix on gas storage and transport mechanisms has gained significant attention, especially during history-matching and hydrocarbon production forecasting in unconventional reservoirs. The common oil and gas industry practice in unconventional reservoir simulation is the extension of conventional reservoir simulation that ignores the dynamic behavior of matrix porosity and permeability as a function of reservoir effective net stress. This approach ignores the significant impact of the poroelastic characteristics of the shale matrix on hydrocarbon production. The poroelastic characteristics of the shale matrix highly relate to the shale matrix geomechanical properties, such as the Young’s Modulus, Poisson’s ratio, bulk modulus, sorption behavior, total organic content (TOC), mineralogy and presence of natural fractures in the multi-scale shale structure. In this study, in order to quantify the effect of the poroelasticity of the shale matrix on gas production, a multi-continuum approach was employed in which the shale matrix was divided into organic materials, inorganic materials and natural fractures. The governing equations for gas transport and storage in shale were developed from the basic fundamentals of mass and momentum conservation equations. In this case, gas transport in organics was assumed to be diffusive, while gas transport in inorganics was governed by convection. Finally, a fracture system was added to the multi-scale shale gas matrix, and the poroelastic effect of the shale matrix on transport and storage was investigated. A modified Palmer and Mansoori model (1998) was used to include the pore compression, matrix swelling/shrinkage and desorption-induced deformation of shale organic matter on the overall pore compressibility of the shale matrix. For the inorganic part of the matrix, relations between rock mechanical properties and the pore compressibility were obtained. A dual Langmuir–Henry isotherm was also used to describe the sorption behavior of shale organic materials. The coupled governing equations of gas storage and transport in the shale matrix were then solved using the implicit finite difference approach using MATLAB. For this purpose, rock and fluid properties were obtained using actual well logging and core analysis of the Marcellus gas well. The results showed the importance of the poroelastic effect on the pressure response and rate of gas recovery from the shale matrix. The effect was found to be mainly due to desorption-induced matrix deformation at an early stage. Coupling the shale matrix gas production including the poroelastic effect in history-matching the gas production from unconventional reservoirs will significantly improve engineering completion design optimization of the unconventional reservoirs by providing more accurate and robust production forecasts for each hydraulic fracture stage.

Localized nonlinear solution strategies for efficient simulation of unconventional reservoirs

Accurate and efficient numerical simulation of unconventional reservoirs is challenging. Long periods of transient flow and steep potential gradients occur due to the extreme conductivity contrast between matrix and fracture. Detailed near-well/near-fracture models are necessary to provide sufficient resolution, but they are computationally impractical for field cases with multiple hydraulic-fracture stages.Previous works in the literature of unconventional simulations mainly focus on the gridding level that adapts to wells and fractures. Limited research has been conducted on nonlinear strategies that exploit locality across timesteps and nonlinear iterations. It was reported that an individual Newton update is typically sparse and nonlinear convergence is constrained by a small portion of the model. To perform localized computations, an a-prioristrategy is essential to first determine the active subset of simulation cells for the subsequent iteration. The active set flags the cells that will be updated, and then the corresponding localized linear system is solved.The objective of this work is to develop localization methods that are readily applicable to complex fracture networks and flow physics in unconventional reservoirs. By utilizing the diffusive nature of pressure updates, an adaptive algorithm is proposed to make adequate estimates for the active domains. In addition, we further develop a localized solver based on nonlinear domain decomposition (DD). Compared to a standard DD method, domain partitions are dynamically constructed. The new solver provides effective partitioning that adapts to flow dynamics and Newton updates.We evaluate the developed methods using several complex problems with discrete fracture networks. The problems consider multi-phase and compositional fluid systems with phase changes. The results show that large degrees of solution locality present across timesteps and iterations. Compared to a standard Newton solver, the new solvers enable superior computational performance. Moreover, Newton convergence behavior is preserved, without any impact on solution accuracy.

Matrix-fracture transfer shape factor for modeling multimechanisitc multicomponent shale gas flow

Numerical simulation of multimechanisitc multicomponent shale gas flow is computationally intensive and a challenging task. Upscaling of pore scale phenomena to Darcy scale simulations is highly desirable to cut down the computational time. Mass transfer between matrix and fracture in dual-porosity simulators has been traditionally upscaled through a pseudo steady state shape factor, which can be obtained analytically thanks to the linear nature of the pressure diffusion in conventional reservoirs. The use of such a shape factor is well established in modeling of fluid flow and transport in conventional reservoirs. However, the shape factor for multimechanisitc multicomponent shale gas flow is not fully realized and its determination is not straightforward due to the non-linear nature of the governing equations. In this work, we present detailed numerical simulation of multimechanisitc multicomponent shale gas flow to obtain shape factor required for Darcy scale numerical simulation of unconventional reservoirs. It is shown that shape factor can be presented as a function of dimensionless pressure (pseudo pressure), which makes application of transient shape factor independent of time. The dependence of the derived shape factor on pressure drawdown, reservoir temperature, Darcy permeability and fluid composition are also investigated. The theoretical analysis improves our knowledge of shale gas flow dynamics and the results find applications in reservoir simulation of gas production from unconventional reservoirs.

A Multi-Scale Modeling of Confined Fluid: from Nanopore to Unconventional Reservoir Simulation

Tight oil and shale gas reservoirs have a significant part of their pore volume occupied by micro (below 2 nm) and mesopores (between 2 and 50 nm). This kind of environment creates strong interaction forces in the confined fluid with pore walls and then changes dramatically the fluid phase behavior. An important work has therefore to be done on thermodynamic modeling of the confined fluid and on developing upscaling methodology of the pore size distribution for large scale reservoir simulations. Firstly, the comparison between molecular simulation results and commonly used modified equation of state (EOS) in the literature highlighted the model of flash with capillary pressure and critical temperature and pressure shift as the best one to model confined fluid behavior. Then, fine grid matrix/fracture simulations have been built and performed for different pore size distributions. The study has shown that the pore size distribution has an important impact on reservoir production and this impact is highly dependent on the volume fraction of nanopores inside the matrix. Afterwards, coarse grid upscaling models have then been performed on the same synthetic case and compared to the reference fine grid results. The commonly used upscaling methodology of dual porosity model with average pore radius for the pore size distribution is unable to match the fine grid results. A new triple porosity model considering fracture, small pores and large pores with their own capillary pressure and EOS, together with MINC (Multiple Interacting Continua) approach, has shown very good agreement with the reference fine grid results. Finally a large scale stimulated reservoir volume with different pore size distribution inside the matrix has been built using the upscaling method developed here.

Robust implementations of the 3D-EDFM algorithm for reservoir simulation with complicated hydraulic fractures

The geometry of the subsurface hydraulic fracture is complicated which deviates from the conventional single pan shape. It can be in multi-wing shape by the formation heterogeneity and/or 3D fracture networks caused by the pre-exising natural fractures. Effective and flexible handling of hydraulic fractures is crucial for the reservoir simulation of unconventional reservoirs. In this paper, we discuss the robust implementations of the 3D-EDFM algorithm, which is applicable to numerical simulation of fluid flow in unconventional reservoirs with complicated, arbitrary 3D hydraulic fracture networks.Key features of this 3D-EDFM methodology consist of vertex-based geometric calculations, and polygons with three to six vertices from box-plane intersections can be captured with this algorithm. The 3D-EDFM has been implemented in reservoir simulators via the integral finite difference (IFD) method. Its numerical scheme and implementation are verified by comparisons with analytical solutions and other established numerical solutions. This method not only provides an effective approach of handling realistic hydraulic fractures, but also significantly improves computational efficiency, while keeping sufficient accuracy. For some extreme cases that the transient state flow lasts long (i.e., large-size matrix blocks with extremely low permeability), our numerical analysis indicates only one level of local grid refinement (LGR) is needed to retain the required accuracy. We also provide an analytical-solution based method to optimize this LGR grid size if needed.This enhanced method is able to handle multiple 3D hydraulic fractures with arbitrary strikes and dip angles, shapes, curvatures, conductivities, and connections. Therefore, the 3D-EDFM provides great flexibility to handle hydraulic-fracture input data, interpreted from geomechanics modelings as well as microseismic data, for reservoir simulation. We present illustrative application examples for three unconventional reservoir engineering problems of interest in practice: (1) a single fracture with a complicated shape due to multi-layer geological features, (2) multiple isolated fractures with curvatures due to the stress shadow effect, and (3) multiple fractures with complicated orientations caused by natural fracture interactions. The 3D-EDFM is demonstrated to capture all the key flow patterns dominated by the discrete fractures in these three cases.

Accelerating and stabilizing the vapor-liquid equilibrium (VLE) calculation in compositional simulation of unconventional reservoirs using deep learning based flash calculation

The flash calculation with large capillary pressure often turns out to be time-consuming and unstable. Consequently, the compositional simulation of unconventional oil/gas reservoirs, where large capillary pressure exists on the vapor-liquid phase interface due to the narrow pore channel, becomes a challenge to traditional reservoir simulation techniques. In this work, we try to resolve this issue by combining deep learning technology with reservoir simulation. We have developed a compositional simulator that is accelerated and stabilized by stochastically-trained proxy flash calculation.We first randomly generated 300,000 data samples from a standalone physical flash calculator. We have constructed a two-step neural network, in which the first step is the classify the phase condition of the system and the second step is to predict the concentration distribution among the determined phases. Each network consists of four hidden layers in between the input layer and the output layer. The network is trained by Stochastic Gradient Descent (SGD) method with 100 epochs.With given temperature, pressure, feed concentration pore radius, the trained network predicts the phases and concentration distribution in the system with very low computational cost. Our results show that the accuracy of the network is above 97% in the metric of mean absolute percentage error. The predicted result is used as the initial guess of the flash calculation module in the reservoir simulator. With the implementation of the deep learning based flash calculation module, the speed of the simulator has been effectively increased and the stability (in the manner of the ratio of convergence) has been improved as well.

CO2, Water and N2 Injection for Enhanced Oil Recovery with Spatial Arrangement of Fractures in Tight-Oil Reservoirs Using Huff-‘n-puff

Tight oil has been effectively developed thanks to artificial fracture technology. The basic mechanism of effective production through fractures lies in the contact between the fractures (both natural and artificial) and the matrix. In this paper, the natural tight cores from J field in China are used to conduct experimental studies on the different fluid huff-‘n-puff process. A new core-scale fracture lab-simulation method is proposed. Woven metallic wires were attached to the outer surface of the core to create a space between the core holder and core as a high permeable zone, an equivalent fracture. Three different injecting fluids are used, including CO2, N2 and water. The equivalent core scale reservoir numerical models in depletion and huff-n-puff mode are then restored by numerical simulation with the Computer Modeling Group—Compositional & Unconventional Reservoir Simulator (CMG GEM). Simulation cases with eight different fracture patterns are used in the study to understand how fracture mechanistically impact Enhanced Oil Recovery (EOR) in huff n puff mode for the different injected fluids. The results showed: Firstly, regardless of the arrangement of fractures, CO2 has mostly obvious advantages over water and N2 in tight reservoir development in huff-‘n-puff mode. Through EOR mechanism analysis, CO2 is the only fluid that is miscible with oil (even 90% mole fraction CO2 is dissolved in the oil phase), which results in the lowest oil phase viscosity. The CO2 diffusion mechanism is also pronounced in the huff-‘n-puff process. Water may impact on the oil recovery through gravity and the capillary force imbibition effect. N2, cannot recover more crude oil only by elasticity and swelling effects. Secondly, the fracture arrangement in space has the most impact on CO2 huff-‘n-puff, followed by water and finally N2. The fractures primarily supply more efficient and convenient channels and contact relationships. The spatial arrangement of fractures mainly impacts the performance of CO2 through viscosity reduction in the contact between CO2 and crude oil. Similarly, the contact between water in fractures and crude oil in the matrix is also the key to imbibition. In the process of N2 huff-‘n-puff, the elasticity energy is dominant and fracture arrangement in space hardly to improve oil recovery. In addition, when considering anisotropy, water huff-‘n-puff is more sensitive to it, while N2 and CO2 are not. Finally, comparing the relationship between fracture contact area and oil recovery, oil production is insensitive to contact area between fracture and matrix for water and N2 cases.

Numerical modeling of gas transport in shales to estimate rock and fluid properties based on multiscale digital rocks

Characterization of rock properties in shale gas reservoirs is vitally important for production forecasting and reserve estimation of natural gas in an efficiently and economically viable fashion. Because of nano-scale pore spaces in organic-rich shale formations, the mechanisms of gas transport in shales are far more complex than those in conventional reservoirs such as sandstone formations. Numerical characterization of shale permeability on multiscale digital rocks has become a powerful tool that greatly complements to lab measurements by combing advanced imaging techniques with numerical simulations. One of the key challenges in unconventional reservoir simulation is how to preserve fine-scale information in coarse-scale reservoir simulation for reliable production forecasting and reserve estimation. Accurate prediction of shale permeability using numerical tools requires well understanding of transport mechanisms at the nano-scale, as well as the upscaling from nano-scale to larger scale simulations. In this work, we present the coupling of MD with LBM on multiple-scale digital rocks, and we develop an upscaling workflow that integrates simulations at nanometer-scale, micrometer-scale, and centimeter-scale. The present approach allows calculating macro-scale transport properties with minimum amount of loss of critical nano/micro-scale information.

Effect of liquid nitrogen cooling on the permeability and mechanical characteristics of anisotropic shale

Liquid nitrogen (LN2) fracturing is a promising new technology for unconventional reservoir simulation because it can effectively solve problems related to low permeability, low brittleness, and water shortage. The present work conducted a series of permeability and strength property-related experiments to evaluate the effect of LN2 cooling on the permeability and mechanical characteristics of anisotropic shale. The main findings of the study are as follows: (1) The influence of the bedding direction on the permeability of anisotropic shale cannot be eliminated by LN2 cooling. LN2 cooling could effectively increase the initial natural damage and the pore space of anisotropic shale, possibly increasing the volume of reservoir stimulation and provide more channels for the seepage and migration of oil and gas. (2) After LN2 cooling, the strength and brittleness of shale are obviously reduced, leading to the decrease in the ability of shale to resist deformation and failure, thereby helping to decrease the initiation pressure of reservoir stimulation. (3) The brittleness of shale will markedly increase during cryogenic fracturing, thus helping to form more complex fracture networks. Based on the present research, LN2 fracturing has obvious advantages compared with hydraulic fracturing in increasing the volume of reservoir stimulation. The results of this study are instructive for understanding the synergistic mechanism of LN2 fracturing and evaluating the effectiveness of reservoir simulation.

Hybrid Coupled Discrete-Fracture/Matrix and Multicontinuum Models for Unconventional-Reservoir Simulation

SummaryUnconventional reservoirs are the focus of considerable attention as a primary energy source. Numerical simulation is a core kernel of reservoir-engineering work flows for reservoir evaluation, optimization, and management. Accurate and efficient numerical simulation of unconventional reservoirs is challenging. There is substantial physical complexity involving a number of tightly coupled mechanisms in the modeling of these reservoirs. The complexity is further amplified by the multicontinuum nature of the stimulated formation, and the complex fracture networks with a wide range of fracture-length scales and topologies.To adequately capture the effects of the multiscaled fracture system, we develop two alternative hybrid approaches that are aimed at combining the advantages of multicontinuum and discrete-fracture/matrix (DFM) representations. During the development of unconventional resources, geological and geophysical information may be available in some cases to suggest a prior characterization, whereas in many other cases, this prior model may be incomplete and limited to hydraulic fractures. The two hybrid approaches could be used for different applications depending on the available characterization data and different requirements for efficiency and accuracy considerations.The first hybrid model couples an embedded-discrete-fracture model (EDFM) with multiple interacting continua (MINC) into EDFM/MINC, which simulates the fracture network characterized by stimulated-reservoir-volume (SRV) concept. This optimized model can reduce the computational cost that is associated with the widely applied logarithmically spaced/locally refined (LS/LR) DFM technique, while improving the flexibility to model the complex geometry of hydraulic fractures. The MINC concept allows the hybrid model to handle the extreme contrast in conductivity between the small-scale fracture network and the ultratight matrix that results in steep potential gradients.For the second class of hybrid model (unstructured DFM/continuum), the primary fractures are described by use of DFM with unstructured gridding, and the small-scale fractures are simulated by continuum-type approaches in a fully coupled manner. Optimized local-grid refinement is used to accurately handle the transient-flow regime around primary fractures. An upscaling technique that applies EDFM on the detailed realization of the discrete-fracture network by use of the target unstructured grid to generate an appropriate dual-permeability model is also developed. The upscaling technique is suitable for cases where a detailed prior model for the complete fracture network is available.Simulation studies demonstrate the applicability of the developed hybrid-fracture models. Model verification is conducted against several reference solutions.

A multi-continuum multi-phase parallel simulator for large-scale conventional and unconventional reservoirs

Reservoir simulation is considered as the core of data analysis during the development of an oilfield. With higher requirements from reservoir engineers, high-resolution geological model problems are commonly used in reservoir simulation. To simulate this kind of large-scale reservoir problems, based on black-oil models and compositional model, a parallel simulator is developed in this paper. Cartesian and corner point grids are supported by our simulator to describe complex geology, including faults and pinch-outs. The multi-continuum models (including a dual-porosity model, a dual-porosity dual-permeability model, and a multiple interacting continua model) are used to simulate fractured reservoirs. Geomechanics effects are successfully involved through a flexible and convenient interface provided by our simulator. Krylov subspace linear solvers, restricted additive Schwarz method, incomplete LU factorization (ILU) preconditioner, and a family of CPR (constrained pressure residual)-type preconditioners are implemented to provide flexibility of the linear system solution processes. Moreover, a new adaptive preconditioning strategy, which can automatically select and change preconditioner between a CPR-type preconditioner and an ILU preconditioner, is designed to accelerate the solution processes and is considered as the most efficient preconditioning technique to our knowledge. MPI-based parallel implementation is employed for each module of the simulator. With the simulator we developed, various conventional and unconventional reservoir simulation problems with large-scale geological models can be achieved on parallel computers within practical computational time. The computational efficiency and parallel scalability are achieved by our high-quality parallel implementation and efficient nonlinear and linear solution techniques.

The present-day stress field of New South Wales, Australia

ABSTRACTThe Australian continent displays the most complex pattern of present-day tectonic stress observed in any major continental area. Although plate boundary forces provide a well-established control on the large-scale (>500 km) orientation of maximum horizontal stress (SHmax), smaller-scale variations, caused by local forces, are poorly understood in Australia. Prior to this study, the World Stress Map database contained 101 SHmax orientation measurements for New South Wales (NSW), Australia, with the bulk of the data coming from shallow engineering tests in the Sydney Basin. In this study we interpret present-day stress indicators analysed from 58.6 km of borehole image logs in 135 coal-seam gas and petroleum wells in different sedimentary basins of NSW, including the Gunnedah, Clarence-Moreton, Sydney, Gloucester, Darling and Bowen–Surat basins. This study provides a refined stress map of NSW, with a total of 340 (A–E quality) SHmax orientations consisting of 186 stress indicators from borehole breakouts, 69 stress measurements from shallow engineering methods, 48 stress indicators from drilling-induced fractures, and 37 stress indicators from earthquake focal mechanism solutions. We define seven stress provinces throughout NSW and determine the mean orientation of the SHmax for each stress province. The results show that the SHmax is variable across the state, but broadly ranges from NE–SW to ESE–WNW. The SHmax is approximately E–W to ESE–WNW in the Darling Basin and Southeastern Seismogenic Zone that covers the west and south of NSW, respectively. However, the present-day SHmax rotates across the northeastern part of NSW, from approximately NE–SW in the South Sydney and Gloucester basins to ENE–WSW in the North Sydney, Clarence-Moreton and Gunnedah basins. Comparisons between the observed SHmax orientations and Australian stress models in the available literature reveal that previous numerical models were unable to satisfactorily predict the state of stress in NSW. Although clear regional present-day stress trends exist in NSW, there are also large perturbations observed locally within most stress provinces that demonstrate the significant control on local intraplate sources of stress. Local SHmax perturbations are interpreted to be due to basement topography, basin geometry, lithological contrasts, igneous intrusions, faults and fractures. Understanding and predicting local stress perturbations has major implications for determining the most productive fractures in petroleum systems, and for modelling the propagation direction and vertical height growth of induced hydraulic fractures in simulation of unconventional reservoirs.

Investigating the Effect of Improved Fracture Conductivity on Production Performance of Hydraulically Fractured Wells: Field-Case Studies and Numerical Simulations

Summary Unconventional reservoirs require extensive hydraulic-fracturing treatments to produce fluids economically and efficiently. The main purpose of such treatments is to create complex fracture networks with high-conductivity paths deeper into the nonstimulated reservoir regions. Proppants play an important role in maintaining good-quality fracture conductivities, which then greatly affect long-term production performance. In addition, research on proppants has shown a reduction in conductivities under downhole stresses and multiphase-flow behaviours. Therefore, it is important to study the effect different proppants and conductivities have on production performance through actual field cases. To evaluate the production performance of wells completed with different proppants, the authors proposed an integrated work flow for characterization and simulation of unconventional reservoirs. This work flow is unique because of the stochastic fracture-network-generation algorithms and improved unstructured-grid-generation techniques. Both analysis of field-production data and numerical simulations were performed on eight wells in the CAPA field of North Dakota. For the field-data analysis, three public-data resources were reviewed to prepare a summary of reservoir properties, fracture properties, proppant properties, and production history. For the numerical simulations, all the wells were modelled and simulated with the proposed work flow. Finally, sensitivity analyses were carried out to investigate the effects of fracture conductivities and natural fractures. After completing the field-case studies and reservoir simulations, it was concluded that with the same fracture design, higher fracture conductivity improves production performance. Pumping a smaller volume of upgraded proppants with higher conductivity not only improves long-term production performance, but also justifies the additional costs and reduces the overall operation time of the entire hydraulic-fracturing job. The stimulated reservoir volume was greatly increased, as was the production performance, where natural fractures exist. In this paper, field-data analysis was applied in the Bakken to demonstrate the integrated unconventional work flow. The proposed unstructured-gridding algorithms can be incorporated into any preprocessor to handle complex networks. Reservoir, fracture, and proppant characterization and reservoir simulation of the field cases can help engineers prepare and interpret simulation input and output.

Impact of Shale-Gas Apparent Permeability on Production: Combined Effects of Non-Darcy Flow/Gas Slippage, Desorption, and Geomechanics

Summary Permeability is one of the most fundamental reservoir-rock properties required for modeling hydrocarbon production. Many shale-gas and ultralow-permeability tight gas reservoirs can have matrix-permeability values in the range of tens to hundreds of nanodarcies. The ultrafine pore structure of these rocks can cause violation of the basic assumptions behind Darcy's law. Depending on a combination of pressure-temperature conditions, pore structure and gas properties, non-Darcy flow mechanisms such as Knudsen diffusion, and/or gas-slippage effects will affect the matrix apparent permeability. Even though numerous theoretical and empirical models were proposed to describe the increasing apparent permeability caused by non-Darcy flow/gas-slippage behavior in nanopore space, few literature sources have investigated the impact of formation compaction and the release of the adsorption gas layer upon shale-matrix apparent permeability during reservoir depletion. In this article, we first present a thorough review on gas flow in shale nanopore space and discuss the factors that can affect shale-matrix apparent permeability, besides the well-studied non-Darcy flow/gas-slippage behavior. Then, a unified shale-matrix apparent-permeability model is proposed to bridge the effects of non-Darcy flow/gas-slippage, geomechanics (formation compaction), and the release of the adsorption gas layer into a single, coherent equation. In addition, a mathematical framework for an unconventional reservoir simulator that was developed for this study is also presented. Different matrix apparent-permeability models are implemented in our numerical simulator to examine how the various factors affect matrix apparent permeability within the simulated reservoir volume. Finally, the impact of a natural-fracture network on matrix apparent-permeability evolution is investigated. The results indicate that, even though the conductive fracture network plays a vital role in shale-gas production, the matrix apparent-permeability evolution during pressure depletion cannot be neglected for accurate production modeling.

Modeling and Simulation of Natural Gas Production from Unconventional Shale Reservoirs

Modeling and simulation of unconventional reservoirs are much more complicated than the conventional reservoir modeling, because of their complex flow characteristics. Mechanisms, which control the flow in the reservoir, are still under the investigation of researchers. However, it is important to investigate applications of mechanisms which are present to our knowledge. This paper presents the theory and applications of flow mechanisms in unconventional reservoir modeling. It is a well-known fact that most of the reservoir flow problems are non-linear due to pressure dependency of particular parameters. It is also widely accepted that fully numerical solutions are costly both computational and time wise. Therefore, the presented model in this paper follows semi-analytical solution methods. Gas adsorption in unconventional reservoirs is the major pressure dependent mechanism; in addition existence of natural fractures is also taken considerable attention. This paper aims to investigate combined effect of existence of natural fractures gas adsorption, and gas slippage effect while keeping the computational effort in acceptable range. Unlike the existing literature (Langmuir is widely used), BET multi-layer isotherm employed in this paper for gas adsorption modeling. A modified dual porosity modeling is used for natural fracture and gas slippage effect modeling. For model verification purposes a history matched is performed with real field data from Marcellus shale. The proposed model in this paper shows a good agreement with the field data. It is observed that BET isotherm models early time production performance more accurately than Langmuir isotherm. It is also concluded that gas adsorption significantly improves the production performances of unconventional reservoirs, with natural fractures. In addition, gas slippage has a slight effect in long term production.

Conceptual study of thermal stimulation in shale gas formations

Shale gas formations have become a major source of energy in recent years. Developments in hydraulic fracturing technology have made these reservoirs more accessible and productive. Apart from other dissimilarities from conventional gas reservoirs, one major difference is that a considerable amount of gas produced from these shale gas formations comes from desorption. Up to 85% of the total gas within shale can be found as an adsorbed phase on clay and kerogen, so how much adsorbed gas can be produced will have significant impact on ultimate gas recovery. The Langmuir isotherm has been widely used in industry to describe the pressure dependence of adsorbed gas. However, temperature dependent adsorption behavior and its major implications for evaluating thermal stimulation as a recovery method for shale reservoirs have not been thoroughly explored. Therefore, in order to design and analyze the thermal treatment of shale gas formations successfully, it is crucial to understand the effects of fracture heating on the shale gas adsorption and desorption phenomenon, and how can we exploit such effects to enhance shale gas recovery from hydraulically fractured reservoirs. Even though numerous research efforts have been focused on thermal recovery of shale oil, its possible application to shale gas has not been investigated.In this research, we propose a method to evaluate desorbed gas as a function of pressure and temperature in shale formations, by regression of a Bi-Langmuir model on Langmuir isotherm data. We have developed a fully coupled unconventional reservoir simulator, which is capable of capturing real gas flow in the shale matrix and in the hydraulic fracture by accounting for the effects of gas desorption and diffusion, as well as the temperature diffusion process within the matrix. This simulator enables us to investigate the effects of fracture heating on the shale gas desorption phenomenon on the global well performance and recovery. The results of this study show, for the first time in a rigorous way, that by increasing the temperature within the fracture, shale gas recovery can be improved.We have rationalized and quantified relations between the adsorption/desorption fundamental phenomena and stimulation temperature, fracture spacing, reservoir permeability and bottom hole pressure. The thermal properties of shale formations only have limited impacts on long term production. The results of this study can provide a guidance to develop a strategy to design thermal treatment in hydraulically fractured shale formations and propose the degree of thermal stimulation temperature required in a fracture to promote an economically viable return on production.