Characterization and Simulation of Discrete Fracture Networks in Unconventional Shale Reservoirs

Fracture characterization and simulation of complex fracture networks are investigated with the emphasis on better and faster approaches to generate fractures by conforming to available data resources, and on accurate, robust, and efficient techniques to grid and discretize complex fracture networks. Three fracture characterization techniques such as fractal-based, microseismic-constrained, and outcrop-based are presented. Natural fractures are generated either stochastically from fractal-based theory, or constrained by microseismic information, or from outcrop maps. Hydraulic fractures are computed from a fast proxy model for fracture propagation that incooperates material balance and lab-measured conductivity data. Then, optimization-based unstructured gridding and discretization technique is developed to handle complex fracture networks with extensively fracture clustering, nonorthogonal and low-angle fracture intersections, and nonuniform fracture aperture distributions. Moreover, through fracture simulation, sensitivity analysis of natural fracture related parameters, nonuniform fracture aperture, and unstructured gridding related parameters on well production performance are investigated, which are followed by well testing behaviors and CO2 EOR of complex fracture networks. This work presents an integrated workflow to model discrete fractures in unconventional shale reservoirs, together with detailed illustrations of each critical component using both synthetic and field application examples

Modelling of Multiphase Fluid flow in Heterogeneous Reservoirs

Computational modeling of multiphase fluid flow in highly heterogenous problems with complicated geometries is a challenging problem for reservoir engineers, with a rich research in establishing best methods and approaches. The novelty in this work is centered around the implementation and comparison of simulation results from two software - the open source ICFESRT and the commercial software ECLIPSE - for a two-phase multiphase problem (oilwater) in both simple and complex geometries. The work involves: (a) implementation and comparison of simulation results from the two software on three different, hypothetical but typical geometries; (b) consideration of a real field case and the associated data analysis, rock characterization, and geostatistics of a real field representative of a highly heterogeneous reservoir; and (c) implementation of both software on the real field case for predictions of oil production at the site, and comparison of the simulation results from the two software. The initial comparison of simulation results for was carried out using three hypothetical (but common) geometries, these being: (a) a quarter five spot with one geological layer; (b) the same geometry as in (a) but with a vertical heterogeneity i.e. 5 different geological layers; (c) and lastly a full 5 spot with 5 different geological layers was implemented. Three different mesh resolutions were applied in both software and comparisons were carried out for mesh-independency. The results showed that in all these three scenarios, good agreement was observed between IC-FERST (coarse mesh) and ECLIPSE (fine mesh) with an average percentage difference at the production well ranging between 2.5% and 10.5% for the oil production and 12% and 26% for the water production. Both the ICFERST and ECLIPSE were subsequently implemented on a real, heterogeneous field – which consisted of 25 producing wells and 8 injections wells. Prior to the software implementation, a data analysis and rock characterization was carried out –Using data from the 33 wells. The logging and core data (a total of 30,000 log readings and 1150 core samples) were utilized and a novel rock characterization technique -Balaha Rock Characterization Code- was implemented to allow for the optimal clustering of rock types within the reservoir, The rock characterization resulted in identifying 7 rock types with their unique porosity-hydraulic permeability relationships. Subsequently, geostatistical methods were implemented – which enabled populating the computational cells of the two software with the corresponding reservoir properties (porosity, hydraulic permeability). To achieve the property population into the unstructured computational domain of the ICFERST software, a newly-developed script was written in Matlab and Python. The rock properties data populated on IC-FERST consist of porosity, permeability, relative permeability, capillary pressure and connate water saturation. A further comparison between the IC-FERST simulation results with the corresponding ECLIPSE simulations was carried out – were all simulations were carried out for a period of 40 years. The percentage differences between the two software simulations were estimated for : (i) ten individual production wells and (ii) the total of all production wells. The results showed that a good agreement exists between the IC-FERST and ECLIPSE simulations, with an average percentage difference for the total oil production of 10.5%, the total water production of 26% and the total water injection of 14%. The results for the ten individual wells showed an average percentage difference of 15.5% ranging from 3 to 29% for the oil production in the late time period. Slightly higher differences were observed when the overall period was considered, due to the large difference at the early time period of the simulation. The results indicated that IC-FERST, when incorporating the necessary rock characterization information – which highlight the heterogeneity of the reservoir – can produce results that can compete with the industry standard ECLIPSE. Additional aspects need to be considered within the current real field IC-FERST simulation, the inclusion of possible fractures and faults, as these were incorporated in the computational domain of ECLIPSE. Additional capabilities also still need to be embedded into IC-FERST, such as the incorporation of the fluid density and viscosity variations with pressure and the consideration of the volume factors, in order to enhance its competitiveness with existing commercial reservoirs simulators such as ECLIPSE

Characterization and Simulation of Discrete Fracture Networks in Unconventional Shale Reservoirs

Fracture characterization and simulation of complex fracture networks are investigated with the emphasis on better and faster approaches to generate fractures by conforming to available data resources, and on accurate, robust, and efficient techniques to grid and discretize complex fracture networks. Three fracture characterization techniques such as fractal-based, microseismic-constrained, and outcrop-based are presented. Natural fractures are generated either stochastically from fractal-based theory, or constrained by microseismic information, or from outcrop maps. Hydraulic fractures are computed from a fast proxy model for fracture propagation that incooperates material balance and lab-measured conductivity data. Then, optimization-based unstructured gridding and discretization technique is developed to handle complex fracture networks with extensively fracture clustering, nonorthogonal and low-angle fracture intersections, and nonuniform fracture aperture distributions. Moreover, through fracture simulation, sensitivity analysis of natural fracture related parameters, nonuniform fracture aperture, and unstructured gridding related parameters on well production performance are investigated, which are followed by well testing behaviors and CO2 EOR of complex fracture networks. This work presents an integrated workflow to model discrete fractures in unconventional shale reservoirs, together with detailed illustrations of each critical component using both synthetic and field application examples

Numerical methods for coupled processes in fractured porous media

Numerical simulations have become essential in the planning and execution of operations in the subsurface, whether this is geothermal energy production or storage, carbon sequestration, petroleum production, or wastewater disposal. As the computational power increases, more complex models become feasible, not only in the form of more complicated physics, but also in the details of geometric constraints such as fractures, faults and wells. These features are often of interest as they can have a profound effect on different physical processes in the porous medium. This thesis focuses on modeling and simulations of fluid flow, transport and deformation of fractured porous media. The physical processes are formulated in a mixed-dimensional discrete fracture matrix model, where the rock matrix, fractures, and fracture intersections form a hierarchy of subdomains of different dimensions that are coupled through interface laws. A new discretization scheme for solving the deformation of a poroelastic rock coupled to a Coulomb friction law governing fracture deformation is presented. The novelty of this scheme comes from combining an existing finite-volume discretization for poroelasticity with a hybrid formulation that adds Lagrange multipliers on the fracture surface. This allows us to formulate the inequalities as complementary functions and solve the corresponding non-linear system using a semi-smooth Newton method. The mixed-dimensional framework is used to investigate non-linear coupled flow and transport. Here, we study how highly permeable fractures affect the viscous fingering in a porous medium and show that there is a complex interplay between the unstable viscous fingers and the fractures. The computer code of the above contributions of the thesis work has been implemented in the open-source framework PorePy. The introduction of fractures is a challenge to the discretization and the implementation of the governing equations, and the aim of this framework is to enable researchers to overcome many of the technical difficulties inherent to fractures, allowing them to easily develop models for fractured porous media. One of the large challenges for the mixed-dimensional discrete fracture matrix models is to create meshes that conform to the fractures, and we present a novel algorithm for constructing conforming Voronoi meshes. The proposed algorithm creates a mesh hierarchy, where the faces of the rock matrix mesh conform to the cells of the fractures, and the faces of the fracture mesh conform to the cells of the fracture intersections. The flexibility of the mixed-dimensional framework is exemplified by the wide range of applications and models studied within this thesis. While these physical processes might be fairly well known in a porous medium without fractures, the results of this thesis improves our understanding as well as the models and solution strategies for fractured porous media

Streamline Tracing and Sensitivity Calculation in Fractured Reservoir with Complex Geometry: Field Application to History Matching and Flood Optimization

The popularity of streamline application mainly depends on two aspects: efficient tracing algorithm to generate streamline, and effective flow and transport analysis along streamline. Previous studies proved its applicability for conventional resources such as waterflood in single and dual porosity models. Streamline technology has limited success in extension to fractured reservoir with discrete fracture networks due to lack of efficient tracing method in the complex porous media geometry. Streamline based application such as history matching and rate optimization also has limitation to gas reservoir depletion or fractured reservoir waterflood due to lack of effective streamline-based flow and transport analysis for highly compressible fluid and highly contrasted porous media. In this study, we first develop streamline tracing method in complex geometry such as faults and discrete fractures. The discrete fractures here are depicted by embedded discrete fracture model (EDFM). We are going to propose novel methods to construct boundary layers for fault non-neighbor connections and EDFM non-neighbor connections. The novel methods reduce the treatment of complex grid geometry to a minimum level and honor the flux of each connection. The utility and validity of this proposed approach is demonstrated using both 2D and 3D examples. Second, we propose an amended streamline-based travel time sensitivity formulation. This novel sensitivity formulation has improved accuracy than the legacy one when compared to numerical perturbed sensitivity, thus results in faster data misfit reduction. We also develop general streamline-based bottom hole pressure sensitivity calculation method suitable for highly compressible fluids or complex geometry caused by non-neighbor connections. The bottom hole pressure sensitivity calculation is validated by a successful history matching application to a high pressure high temperature gas reservoir. Finally, we develop a rate allocation optimization method based on fast estimation of oil recovery, which also applies to fractured reservoirs. The oil recovery is estimated along streamline within the drainage volume by the end of optimization period. The injection/production rates are updated to maximize the field oil recovery. The novel optimization method results in better performance than equalizing well pair injection efficiency or equalizing well pair time of flight when applying to a waterflood case in fractured reservoir. Its validation is further established by the waterflood optimization application to a field scale EDFM reservoir. We concluded that our proposed approach of streamline tracing, inversion and optimization algorithm extends streamline technology application to fractured media represented by discrete fracture networks and highly compressible fluid, leading to a highly effective reservoir management tool

Research Advance on Prediction and Optimization for Fracture Propagation in Stimulated Unconventional Reservoirs

AbstractMultistage stimulation horizontal wells are prerequisite technologies for efficient development of unconventional reservoir. However, the induced fracture network morphology from hydraulic fracturing is very complex and affected by many factors, such as the in situ stress, rock mechanical properties, and natural fracture distribution. The large numbers of natural fractures and strong reservoir heterogeneity in unconventional reservoirs result in enhanced complexity of induced fractures from hydraulic fracturing. Accurate description of fracture network morphology and the flow capacity in different fractures form an important basis for production forecasting, evaluation (or optimization) of stimulation design, and development plan optimization. This paper focuses on hydraulic fracturing in unconventional reservoirs and discusses the current research advances from four aspects: (1) the prediction of induced fracture propagation, (2) the simulation of fluid flow in complex fracture networks, (3) the inversion of fracture parameter (fracture porosity, fracture permeability, etc.), and (4) the optimization of hydraulic fracturing in unconventional reservoirs. In addition, this paper provides comparative analysis of the characteristics and shortcomings of the current research by outlining the key technical problems in the study of flow characterization, parameter inversion, and optimization methods for stimulation in unconventional reservoirs. This work can provide a certain guiding role for further research

The impact of grid geometry on displacement calculations

Reservoir simulation models are becoming increasingly sophisticated in tandem with the rapid development of geological modeling methods. Widely used commercial simulators usually model flow through heavily faulted and structurally complex geometries with the flexibility provided by corner-point geometry. However, the nonorthogonality component present within these frameworks may compromise the solution accuracy of the model and the subsequent operational decisions involved. We propose a systematic methodology to evaluate the impact of complex gridding introducing a new streamline formulation for corner-point geometry. Based on a new time-like variable, the new formulation provides a significantly simpler and more robust development to handle the complexity in structurally demanding and faulted systems. It retains the simplicity and speed of streamline-based flow models and provides an efficient way to visualize nonorthogonal effects. Applied to various geometries showing challenging features of geology and flow, the displacement fronts obtained from streamline-derived analytic calculation identified the discrepancies characteristic between known solutions and results from two widely used commercial simulators

Geostatistical integration of geophysical, well bore and outcrop data for flow modeling of a deltaic reservoir analogue

Significant world oil and gas reserves occur in deltaic reservoirs. Characterization of deltaic reservoirs requires understanding sedimentary and diagenetic heterogeneity at the submeter scale in three dimensions. However, deltaic facies architecture is complex and poorly understood. Moreover, precipitation of extensive calcite cement during diagenesis can modify the depositional permeability of sandstone reservoir and affect fluid flow. Heterogeneity contributes to trapping a significant portion of mobile oil in deltaic reservoirs analogous of Cretaceous Frontier Formation, Powder River Basin, Wyoming. This dissertation focuses on 3D characterization of an ancient deltaic lobe. The Turonian Wall Creek Member in central Wyoming has been selected for the present study, which integrates outcrop digitized image analysis, 2D and 3D interpreted ground penetrating radar surveys, outcrop gamma ray measurements, well logs, permeameter logs and transects, and other data for 3D reservoir characterization and flow modeling. Well log data are used to predict the geological facies using beta-Bayes method and classic multivariate statistic methods, and predictions are compared with the outcrop description. Geostatistical models are constructed for the size, orientation, and shape of the concretions using interpreted GPR, well, and outcrop data. The spatial continuity of concretions is quantified using photomosaic derived variogram analysis. Relationships among GRP attributes, well data, and outcrop data are investigated, including calcite concretion occurrence and permeability measurements from outcrop. A combination of truncated Gaussian simulation and Bayes rule predicts 3D concretion distributions. Comparisons between 2D flow simulations based on outcrop observations and an ensemble of geostatistical models indicates that the proposed approach can reproduce essential aspects of flow behavior in this system. Experimental design, analysis of variance, and flow simulations examine the effects of geological variability on breakthrough time, sweep efficiency and upscaled permeability. The proposed geostatistical and statistical methods can improve prediction of flow behavior even if conditioning data are sparse and radar data are noisy. The derived geostatistical models of stratigraphy, facies and diagenesis are appropriate for analogous deltaic reservoirs. Furthermore, the results can guide data acquisition, improve performance prediction, and help to upscale models

Streamline Tracing and Sensitivity Calculation in Fractured Reservoir with Complex Geometry: Field Application to History Matching and Flood Optimization

The popularity of streamline application mainly depends on two aspects: efficient tracing algorithm to generate streamline, and effective flow and transport analysis along streamline. Previous studies proved its applicability for conventional resources such as waterflood in single and dual porosity models. Streamline technology has limited success in extension to fractured reservoir with discrete fracture networks due to lack of efficient tracing method in the complex porous media geometry. Streamline based application such as history matching and rate optimization also has limitation to gas reservoir depletion or fractured reservoir waterflood due to lack of effective streamline-based flow and transport analysis for highly compressible fluid and highly contrasted porous media. In this study, we first develop streamline tracing method in complex geometry such as faults and discrete fractures. The discrete fractures here are depicted by embedded discrete fracture model (EDFM). We are going to propose novel methods to construct boundary layers for fault non-neighbor connections and EDFM non-neighbor connections. The novel methods reduce the treatment of complex grid geometry to a minimum level and honor the flux of each connection. The utility and validity of this proposed approach is demonstrated using both 2D and 3D examples. Second, we propose an amended streamline-based travel time sensitivity formulation. This novel sensitivity formulation has improved accuracy than the legacy one when compared to numerical perturbed sensitivity, thus results in faster data misfit reduction. We also develop general streamline-based bottom hole pressure sensitivity calculation method suitable for highly compressible fluids or complex geometry caused by non-neighbor connections. The bottom hole pressure sensitivity calculation is validated by a successful history matching application to a high pressure high temperature gas reservoir. Finally, we develop a rate allocation optimization method based on fast estimation of oil recovery, which also applies to fractured reservoirs. The oil recovery is estimated along streamline within the drainage volume by the end of optimization period. The injection/production rates are updated to maximize the field oil recovery. The novel optimization method results in better performance than equalizing well pair injection efficiency or equalizing well pair time of flight when applying to a waterflood case in fractured reservoir. Its validation is further established by the waterflood optimization application to a field scale EDFM reservoir. We concluded that our proposed approach of streamline tracing, inversion and optimization algorithm extends streamline technology application to fractured media represented by discrete fracture networks and highly compressible fluid, leading to a highly effective reservoir management tool