Executive Summary

This issue brings you 20 papers divided into three sections.

Fracturing and Unconventional Resources. The first section consists of 10 papers discussing various aspects of hydraulic fracturing and recovery of unconventional resources.
  The first paper by Haddad et al. discusses microseismic mapping during the hydraulic-fracturing process in the Vaca Muerta Shale in Argentina. The mapping shows microseismic events occurring at shallower depth and at later injection time, which deviate clearly from the growing planar hydraulic fracture. The paper seeks to investigate the nature of these events and their connection to the fracturing process.
  Pang et al. develop correlations for effective porosity and permeability that consider the combined effects of gas adsorption and stress for shale with nanoscale porosity and permeability. The correlations show that porosity and permeability decline with increasing pore pressure.
Aljamaan et al. use a novel multiscale-imaging methodology, spanning from centimeter to nanometer scale, to analyze and determine gas-storage capacities for four intact 2.54-cm-diameter cores from different shale plays. The work supports the potential of carbon storage in shale formations and guides engineers toward optimal CO2-injection zones for enhanced gas recovery.
  Lan et al. propose a mathematical model that uses mercury-injection capillary pressure data to determine the accessible-pore and inaccessible part of the rock compressibility as a function of pressure. The model is used to demonstrate that substitution of total pore compressibility with accessible-pore compressibility can significantly change the prediction of reservoir behavior, giving much higher production caused by rock compaction than what has often been regarded.
  Mao et al. extend classical diagnostic plots of dimensionless fracture conductivity versus equivalent wellbore radius or equivalent negative skin to the case of horizontal wells with multiple fractures and demonstrate applications for fracture-design optimization.
  Yang et al. develop a semianalytical model that incorporates two-phase flow in both fracture and matrix for multifractured horizontal wells. The model is used to analyze multistage hydraulic fracturing and history match a horizontal well in the Marcellus shale during the flowback period.
  The paper by Xiao et al. develops an analytical pressure-transient model in the Laplace domain to detect interacting behavior between hydraulic and natural fractures, which can be used to accurately and efficiently characterize the complex fracture system induced by hydraulic fracturing. In a similar vein, Jia et al. present another model in the Laplace domain for multiwell pads that describes interwell communication in terms of flow in matrix and primary and secondary fractures. 
  Liu and Valkó study development plants of shale gas or tight oil in large square drainage areas (sections) and propose a convenient section-based optimization method of the fracture array based on a reliable and efficient productivity-index calculation for the boundary-dominated state. 
  Wu and Sharma study fluid flow in unpropped and natural fractures and develop a numerical model that integrates elastoplastic deformation and deformation interaction to simulate stress-driven closure and conductivity for fractures with rough surfaces. The model compares well with experimental data and is used to demonstrate that plastic deformation is a dominant contributor to closure and can make up more than 70% of the total closure in some shales. 

Reservoir Simulation, Optimization, and History Matching. Khorsandi et al. develop a novel equation of state to robustly model relative permeability as a function of phase saturation and distributions, fluid compositions, rock-surface properties, and rock structure. The aim of this development is to better capture the effects of hysteresis, fluid compositional variations, and wettability alterations compared with conventional empirical relations based on fitting of experimental data.
  Multiscale methods seek to accelerate reservoir simulation by computing approximate pressures as a linear combination of local flow solutions computed over individual blocks in a coarsened grid model. Lie et al. demonstrate that this method can be further accelerated and made more robust if one uses an alternating sequence of different coarse grids, whose shape may adapt to reservoir heterogeneity or precomputed flow solutions, instead of a single coarse grid. 
  Flow diagnostics is a common way to rank and cluster ensembles of reservoir models. The key idea is to approximate dynamic reservoir behavior in terms of volumetric connections (swept volumes, well-allocation factors) and various measures of dynamic heterogeneity (flow/storage capacity, Lorenz coefficients) that can be computed quickly by solving stationary flow equations. The paper by Zhang et al. discusses flow diagnostics in the setting of rapid-reservoir modeling, which aims at fast and intuitive prototyping of geologically realistic reservoir models, and presents a new numerical method designed for fully unstructured grids.
  The paper by Olorode et al. proposes a new compositional reservoir-simulation model for gas-bearing organic-rich source rocks. The multiscale model consists of three continua: organic (kerogen), inorganic (matrix), and fracture. A simple mass-balance equation enables kerogen to transfer gas to the surrounding inorganic matrix, whereas convective/diffusive transport between neighboring gridblocks only takes place in the organic matrix.
  Fu and Wen discuss multiobjective optimization, which accounts for several distinct and possibly conflicting objectives that can be used to improve reservoir-management solutions. The paper compares and contrasts three different methods: an adjoint method and two population-based methods that combine the Pareto technique with a genetic algorithm or particle-swarm optimization. 
  A persistent problem in history matching is how to efficiently solve large systems of nonlinear equations. Gao et al. propose the use of a trust-region method, which transforms the nonlinear optimization problem to a quadratic problem, in combination with Gauss-Newton solver and show that this gives a robust and efficient solution procedure for real-reservoir models.
  Wantawin et al. present a new response-surface method for history matching shale-gas reservoirs, in which history matching is combined with an uncertainty-assessment process. As more probabilistic forecasts are evaluated, the proxy models are gradually changed into higher-degree polynomials so that they are more accurate and cover a wider uncertainty range. The method is applied to a horizontal hydraulic-fractured well in the Marcellus Shale formation.

Acidizing. The last three papers study wormhole propagation in carbonate-matrix acidizing. 
  Hosseinzadeh et al. develop an improved rheology model to better describe the diversion by polymer-based in-situ-gelled acids. 
Akanni et al. use a Navier-Stokes momentum approach to develop an efficient simulation method for accurately capturing the dissolution regimes that occur during carbonate-matrix acidizing. Their simulations show that optimal injection rates obtained in laboratory coreflood experiments cannot be directly translated for field applications because of the effect of flow geometry and medium dimensions on the wormholing process. 
  Wei et al. develop a two-phase, two-scale model that accounts for convective, dispersive, and reactive effects to describe wormhole propagation in radial coordinates. The model is validated against simulation results and analytical solutions.

Acknowledgements. On behalf of SPE Journal and our readers, I thank all those who have contributed to write and review the papers in this issue.


Knut-Andreas Lie, SPE Journal Executive Editor;
SINTEF Digital/NTNU