bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Three-Dimensional Reservoir, Wellbore, and Hydraulic Fracturing Simulator that is Compositional and Thermal, Tracks Proppant and Water Solute Transport, Includes Non-Darcy and Non-Newtonian Flow, and Handles Fracture Closure
Authors: McClure Mark W. , Kang Charles A. 
Published: February 2017

Abstract
We present a three-dimensional reservoir, wellbore, and hydraulic fracturing simulator with the following capabilities: (1) compositional fluid model, (2) multiphase flow, (3) thermal, (4) proppant transport with gravitational settling, bulk slurry gravitational convection, hindered settling, clustered settling, and the effect of proppant concentration on slurry viscosity, (5) solute transport, (6) non-Newtonian fluid rheology with the modified power law (capable of representing the low shear rate viscosity plateau), (7) non-Darcy flow in the fractures, and (8) the ability to handle fracture closure. The simulator is still a work-in-progress; additional features are planned in future work. The simulator is a practical tool for designing hydraulic fracturing treatments and predicting future production. The combination of reservoir and fracturing simulation enables: (1) comparison of proposed frac designs on the basis of predicted production, (2) more realistic simulation of pressure drawdown in the fracture during production by using flow equations designed for fracture flow, (3) description of processes involving tight coupling of production and stimulation, such as refracturing, and (4) avoidance of tedious handoffs between separate fracturing and reservoir simulation codes. We develop general-purpose constitutive equations for fracture transport that are realistic for mechanically open or closed fractures and for all values of proppant mass per fracture area. In limiting cases, the equations reduce to well-known constitutive equations, such as Darcy's law, the cubic law, and Forchheimer's law. Between limiting cases, the equations smoothly transition between governing regimes. The current model is applicable for hydraulic fracturing in formations that do not exhibit strong fracture network "complexity" during stimulation. Modeling stimulation of secondary fractures requires special considerations that are not implemented in the current version of the code. We demonstrate the model capabilities with a generic simulation of a single-stage frac job from a vertical well, followed by production. After the injection of a pad, water is injected with 60 mesh proppant. This is followed by lower rate injection of water gelled with guar and 20 mesh proppant. The fracturing treatment generates a large, well-propped fracture. The fracture propagates below the water-hydrocarbon contact, resulting in significant watercut during production.
Molecular Diffusion Calculations in Simulation of Gasfloods in Fractured Reservoirs
Authors: Mohebbinia Saeedeh , Wong Terry 
Published: February 2017

Abstract
Molecular diffusion is a proven oil recovery mechanism in fractured reservoirs. Neglecting diffusion during the simulation of gas injections can lead to underestimated oil recoveries. This is particularly important in fractured reservoirs with low permeabilities. This paper presents the implementation of a diffusion model in a reservoir simulator. The implementation is verified with discrete fracture and dual-porosity model cases. The adopted diffusion model is based on irreversible thermodynamics. It uses full matrices of diffusion coefficients and chemical potential gradients as the driving force. To evaluate how much diffusion is dominant during fluid flow in fractured reservoirs, a form of the Péclet number is proposed as the ratio of characteristic times of diffusion to gravity drainage for a given reservoir and fluid properties. The incremental oil recovery from gas injection simulation results confirms the flow regime predicted by the Péclet number. This paper also examines the performance of simulations that involve diffusion by using various solution schemes, including explicit, fully implicit, and partially implicit methods. Optimal performance is achieved with the partially implicit method in which diffusion coefficients are updated at each timestep, while driving forces are updated inside Newton iterations. The simulation results also show that constant diffusivities might not provide a good representative for diffusion coefficients during gasflooding. They can cause oil recovery overestimation or underestimation. The authors demonstrate a technique to forgo diffusion calculations in the regions with convection-dominated flow regimes to help reduce computational time of the simulations involving diffusion. The speedup obtained for gas injection cases with a wide range of Péclet numbers is also examined.
Fully Coupled Thermal-Hydraulic-Mechanical Reservoir Simulation with Non-Isothermal Multiphase Compositional Modeling
Authors: Wang Shihao , Zhang Juncheng , Yang Zhenzhou , Yin Congbin , Wang Yonghong , Zhang Ronglei , Winterfeld Philip , Wu Yu-Shu 
Published: February 2017

Abstract
We present the development and application of a multi-physical simulator for evaluating the combined thermal-hydraulic-mechanical behaviors of petroleum reservoirs. The simulator combines non-isothermal multiphase compositional modeling with coupled geomechanical simulation module. The simulator consists of two major modules, namely, the fluid and heat flow module and the geomechanical module. An isenthalpic flash calculation approach is implemented in the fluid and heat flow module. In the flash calculation module, a nested approach is adopted, in which PT flash calculations are conducted in the inner loop and temperature is updated in the outer loop. The iteration is continued until both the fugacity and energy stopping criteria are satisfied. An improved version of the Beltrami-Michell equation, called extended Beltrami-Michell equation, has been derived and implemented in the geomechanical simulation module to simulate heterogeneous and plastic behavior of formation rocks. The three normal stress components inside the stress tensor are solved simultaneously with the pressure and enthalpy in the fluid/heat module, ensuring the mass/energy conservation. The newly-derived extension of the Beltrami-Michell equation is capable of handling materials with changing mechanical properties. This way, the simulator is able to capture the phase change as well as the poro-mechanical effects on rock deformation induced by fluid injection/extraction. The multi-physics simulator is built on an object-oriented parallel simulation framework, with a speedup factor up to hundreds.
A Practical Method to Mitigate Spurious Uncertainty Reduction in History Matching Workflows with Imperfect Reservoir Models
Authors: Sun Wenyue , Vink Jeroen C. , Gao Guohua 
Published: February 2017

Abstract
History matching within the Bayesian framework in practice assumes perfect simulation models. However, for real field cases this assumption may lead to a spurious reduction in forecast uncertainty when a large number of data is used to constrain imperfect reservoir models. To mitigate this spurious uncertainty reduction, we propose a new approach to automatically and consistently inflate the standard deviation of measurement errors for the constraining field data. In previous work we applied the simple mitigation strategy of using a single inflation factor for all data. In this work we propose to use information from the Hessian matrix evaluated at the maximum a posteriori (MAP) points in parameter space: data are regrouped into different categories according to their sensitivities with respect to principal directions of the posterior Hessian matrix. For each group a suitable inflation factor can then be estimated from the number of data and observed mismatches in that group. The proposed procedure is applied to a synthetic as well as a field scale model. The truth of the synthetic model is selected from one unconditional realizations of a real field model with three facies. Synthetic measured production data are generated by adding Gaussian noise to those predicted from the true simulation model. During the process of history matching, a few uncertain model parameters are artificially fixed to values that are inconsistent with the truth to mimic the unknown real field case and make the model imperfect. Numerical results indicate that the proposed approach is able to give a balanced and reasonable range of forecast uncertainty for the cases considered.
Impact of Capillary Pressure and Critical Property Shift due to Confinement on Hydrocarbon Production in Shale Reservoirs
Authors: Haider B. A. , Aziz K. 
Published: February 2017

Abstract
Interest in understanding the underlying physical mysteries that result in production from liquid rich shale (LRS) reservoirs is growing globally. Compositional modeling of fractured multiphase shale reservoirs is a complex process that is yet to be fully understood. Our quest in this work is to explore some of the key fundamentals of flow in nano-porous media. This study analyzes the impact of capillary pressure and critical property shifts due to the pore proximity effect on hydrocarbon production in multiple realistic scenarios of flow in shale reservoirs. While many past researches have attempted to show the significance of nano-forces in shale reservoirs, the actual impact that these have on large-scale hydrocarbon production is not fully understood. Response of wells in shale oil reservoirs is tied to both reservoir conditions and fluid system of interest. This work provides an assessment of the magnitude and the ultimate significance of the forces that arise in tight pores, using a fully compositional reservoir simulator. We studied the impact of capillary pressure amidst variations in pore size distributions, fluid composition, reservoir pressure conditions and the presence of fractures that are typical to shale reservoirs. In conventional compositional modeling phase behavior is assumed to be independent of capillary pressure. However, in the presence of nano-pores the magnitude of the differences in phase pressures can be very large. Here we present a systematic study of the influence of this phenomenon on recovery from shale reservoirs.
Our findings indicate that the impact of these nano-forces on hydrocarbon production is influenced by variations in shale reservoir/fluid properties. Shale reservoirs entail a great deal of geological uncertainty, and can contain a wide spectrum of hydrocarbon fluids that may range from low GOR black oil to dry gas. Further complications arise from uncertain pore size distribution and improperly characterized fracture networks.
Coupled Reservoir-Geomechanical Simulation of Caprock Failure and Fault Reactivation During CO2 Sequestration in Deep Saline Aquifers
Authors: Winterfeld P. H. , Wu Yu-Shu 
Published: February 2017

Abstract
An aquifer suitable for underground carbon dioxide sequestration needs to be overlain by sealing caprock because carbon dioxide is less dense than the native brine and would tend to rise upward. This paper presents a thermal-hydrological-mechanical (THM) reservoir simulator that is applicable to assessing the sealing capability of such caprock. The geomechanical portion consists of an equation for mean stress, derived from linear elastic theory for a thermo-poro-elastic system, and equations for stress tensor components that depend on mean stress and other variables. The fluid and heat flow portion of our simulator is for general multiphase, multicomponent, multi-porosity systems. We add the capability of simulating caprock failure scenarios, namely tensile failure, fracture and fault reactivation, and shear failure, to the formulation. We then show simulation examples for code verification and demonstration of its capabilities, including a simulation of caprock leakage from carbon dioxide injection, a demonstration of the simulator's ability to predict of shear failure, and a simulation an experiment of pressure-induced fracturing of a concrete block that includes tensile failure.
A Discontinuous Galerkin Finite Element Framework for the Direct Numerical Simulation of Flow on High-Resolution Pore-Scale Images
Authors: Frank Florian , Liu Chen , Alpak Faruk O. , Araya-Polo Mauricio , Riviere Beatrice 
Published: February 2017

Abstract
Advances in pore-scale imaging, increasing availability of computational resources, and developments in numerical algorithms have started rendering direct pore-scale numerical simulations of multiphase flow on pore structures feasible. In this paper, we describe a two-phase flow simulator that solves mass and momentum balance equations valid at the pore scale, i.e. at scales where the Darcy velocity homogenization starts to break down. The simulator is one of the key components of a molecule-to-reservoir truly multiscale modeling workflow.
A Helmholtz free-energy driven, thermodynamically based diffuse-interface method is used for the effective simulation of a large number of advecting interfaces, while honoring the interfacial tension. The advective Cahn–Hilliard (mass balance) and Navier–Stokes (momentum balance) equations are coupled to each other within the phase-field framework. Wettability on rock-fluid interfaces is accounted for via an energy-penalty based wetting (contact-angle) boundary condition. Individual balance equations are discretized by use of a flexible discontinuous Galerkin (DG) method. The discretization of the mass balance equation is semi-implicit in time; momentum balance equation is discretized with a fully-implicit scheme, while both equations are coupled via an iterative operator splitting approach.
We discuss the mathematical model, DG discretization, and briefly introduce nonlinear and linear solution strategies. Numerical validation tests show optimal convergence rates for the DG discretization indicating the correctness of the numerical scheme. Physical validation tests demonstrate the consistency of the mass distribution and velocity fields simulated within our framework. Finally, two-phase flow simulations on two real pore-scale images demonstrate the utility of the pore-scale simulator. The direct pore-scale numerical simulation method overcomes the limitations of pore network models by rigorously taking into account the flow physics and by directly acting on pore-scale images of rocks without requiring a network abstraction step or remeshing. The proposed method is accurate, numerically robust, and exhibits the potential for tackling realistic problems.
Simulation of Matrix-Fracture Interaction in Low-Permeability Fractured Unconventional Reservoirs
Authors: Ding D. Y. , Farah N. , Bourbiaux B. , Wu Y-S. , Mestiri I. 
Published: February 2017

Abstract
Unconventional reservoirs, such as shale-gas or tight-oil reservoirs, are generally highly fractured, including hydraulic fractures, stimulated and non-stimulated natural fractures of various sizes, embedded in low-permeability formations. One of the main production mechanisms in unconventional reservoirs is the flow exchange between matrix and fracture media. However, due to extremely-low matrix permeability, the matrix/fracture exchange is very slow and the transient flow may last several to tens of years, i.e. almost the entire production life. The commonly-used dual-porosity modelling approach involves a computation of pseudo-steady-state matrix-fracture transfers with homogenized fluid and flow properties within the matrix medium. This kind of model clearly fails to handle the long-lasting matrix/fracture interaction in very-low permeability reservoirs, especially for multi-pahse flow with phase change problems. Moreover, a dual-porosity model is not adapted for the simulation of matrix/fracture exchange when fractures are described by a DFN (Discrete Fracture Network). This paper presents an EDFM (Embedded Discrete Fracture Model) based on the MINC (Multiple INteracting Continua) proximity function to overcome this insufficiency of the conventional dual-porosity model.
Multirate Coupling for Flow and Geomechanics Applied to Hydraulic Fracturing Using an Adaptive Phase-Field Technique
Authors: Almani Tameem , Lee Sanghyun , Wheeler Mary F. , Wick Thomas 
Published: February 2017

Abstract
We present and analyze a multirate fixed stress split iterative coupling scheme for coupling flow and geomechanics in a poroelastic medium involving fracture propagation modeled with a phase field approach. The novelty of this work lies in the efficient integration of the fixed-stress split coupling scheme with phase-field fracture propagation models. The multirate coupling algorithm utilizes different time-scales of the flow and mechanics problems, by allowing for multiple finer time steps for flow within one coarse mechanics time step. When applied to production scenarios, the multirate scheme results in massive reductions in the number of mechanics linear iterations, without jeopardizing the accuracy of the obtained results. A number of numerical simulations substantiate our algorithmic developments. These tests include prototype computations, multiple propagating fractures, and fractures initialized by a microseismic probability map.
Field-Scale Assisted History Matching Using A Systematic, Massively Parallel Ensemble Kalman Smoother Procedure
Authors: Lin Binghuai , Crumpton Paul I , Dogru Ali H. 
Published: February 2017

Abstract
This work presents a systematic and rigorous approach of reservoir decomposition combined with the ensemble Kalman smoother to overcome the complexity and computational burden associated with history-matching field-scale reservoirs in the Middle East. The results demonstrate the performance and feasibility of this integrated method.
The ability of the ensemble smoother to quantify the uncertainty of complex nonlinear models and handle a high dimensional parameter space has made it an extremely useful algorithm. However, for large fields with their associated amount of observational data the expense of this method can be prohibitive. To overcome this issue, the reservoir is decomposed into overlapping domains based on the prior knowledge of the geological and fluid flow features of the reservoir, and an improved iterative ensemble Kalman smoother is applied to each domain. For each iteration the ensemble updating is regularized to control the parameter increments and avoid filter divergence. Localization is employed to minimize spurious long-distance correlations and reduce the boundary effects between the domains. Each sub-domain exploits a parallel cluster, both to run each simulation within the ensemble independently, and then to run each reservoir simulation in parallel. The Kalman update itself cannot be implemented in a naive way because of the memory consideration of the large matrices involved. Instead, the HDF5 file format is utilized for efficient out-of-core memory reading/writing of the large matrices and facilitating the matrix operations.
The method is applied to a 60-million-cell Middle East field model. The systematic approach here decomposes the original reservoir into six smaller pieces. The ensemble smoother, with an ensemble size of 50, is then applied to the individual reservoir domains to generate history-matched models; this exploits a 3000-node cluster with 24 cores on each node. Each of the simulation runs takes 2-3 hours on 500 cores; the overall history matching process can be performed in about one week. The results of the models are then combined together to reconstruct the original reservoir. Compared to history-matching results from months of effort of the engineers, the ensemble smoother takes much less manpower to achieve better match to the data.
This parallel iterative ensemble smoother has demonstrated the feasibility and performance of history-matching large-scale complex real field reservoirs. By combining domain decomposition, the systematic history-matching workflow can also be applied to large Middle-East reservoirs, which generally cannot be achieved using other methods.
Improving the Computational Efficiency of Approximate Gradients Using a Multiscale Reservoir Simulation Framework
Authors: Moraes R. , Fonseca R. M. , Helici M. , Heemink A. W. , Jansen J. D. 
Published: February 2017

Abstract
We present an efficient workflow that combines multiscale (MS) forward simulation and stochastic gradient computation - MS-StoSAG - for the optimization of well controls applied to waterflooding under geological uncertainty. The Iterative Multiscale Finite Volume (i-MSFV), a mass conservative reservoir simulation strategy, is employed as the forward simulation strategy. The i-MSFV method has the ability to accurately capture fine scale heterogeneities, and thus the fine scale physics of the problem. This allows for accurate and efficient simulations with fine-scale error estimates in a more computationally efficient coarse-scale simulation grid. The Stochastic Simplex Approximate Gradient (StoSAG) method, a stochastic gradient technique, inspired from Ensemble Optimization (EnOpt), is employed to compute the gradient of the objective function. Stochastic methods have recently been shown to be very efficient in terms of gradient quality and computational cost especially for robust optimization problems. They rely on the reservoir simulator as a black-box and perform a large number of forward simulations to approximate a gradient. In our numerical experiments, we investigate the impact of MS parameters such as coarsening ratio and heterogeneity contrast on the quality of the approximate MS-StoSAG gradient. Our experiments illustrate that i-MSFV simulations provide accurate forward simulation responses for the gradient computation, with the advantage of speeding up the workflow due to faster simulations. Speedups up to a factor of five on the forward simulation were achieved for the examples considered in the paper. The combination of speed and accuracy of MS forward simulation with the flexibility of the StoSAG technique (several different parameters/responses can be easily considered) allows for a flexible and efficient optimization strategy suitable for large-scale problems.
Mechanistic Simulation Workflow in Shale Gas Reservoirs
Authors: Yan Bicheng , Mi Lidong , Wang Yuhe , Tang Hewei , An Cheng , Killough John E. 
Published: February 2017

Abstract
Shale gas reservoir is comprised of highly heterogeneous porosity systems including hydraulic/secondary fractures, inorganic and organic matrix. Multiple non-Darcy flow mechanisms in the shale matrix further bring challenges for modeling. In this paper, we developed a framework combining a multi-physics compositional simulator with Multi-Porosity Modeling preprocessor for gas storage and transport in shale. A Triple-Porosity Model is used to characterize the three porosity systems in shale gas reservoirs. In the fracture porosity the heterogeneous impact of secondary fractures distribution on matrix-to-fracture fluid transfer is revealed by shape factor distribution. They are upscaled with superior accuracy from a detailed Discrete Fracture Network Model (DFN) sector model, where orthogonal hydraulic fractures are explicitly discretized. With the occurrence of nano-pores in shale matrix, the interaction between pore-wall and gas molecules is considered via Knudsen diffusion and gas slippage. Gas adsorption on the pore-wall of organic matrix is modeled by extended Langmuir isotherm. The inter-porosity and intra-porosity connectivities in the Triple-Porosity Model are flexibly controlled by arbitrary connections. Our results show that gas production in the Triple-Porosity Model with shape factor upscaled from DFN exhibits different production performance from models with uniform shape factor distribution. The deviations are caused by the dominance of different regions at different production periods. Moreover, different combinations of flow and storage mechanisms are investigated. We show that Langmuir desorption maintains reservoir pressure, but gas slippage and Knudsen diffusion accelerate the pressure drop. Both mechanisms contribute to improve the gas production and the consideration of them simultaneously improve gas production most.