Scientific publishing is currently undergoing a substantial change toward open access (OA), driven in part by digitization, widespread public access to internet, and a perception of disproportionate increases in subscription fees. Wikipedia defines OA publishing as online research outputs that are free of all restrictions on access (e.g. access tolls) and free of many restrictions on use (e.g. certain copyright and license restrictions). OA to peer-reviewed research papers can be divided into main categories. In so-called “gold” OA, authors can make their paper immediately available from the publisher. Pure OA journals do not charge a subscription fee, but may charge article processing fees. Many well-reputed journals use a hybrid model, and only offer OA to those papers for which an article processing fee has been paid. In the “green” OA model, authors are allowed to self-archive their paper on their personal website, on their institution’s website, or in an online repository such as arxiv.org, PubMed Central, or ResearchGate. To provide value to their subscribers, many journals only allow self-archiving after a certain embargo period.
In Europe, the Netherlands has been a forerunner for a more general Open Science initiative, which, quoting from the “Amsterdam Call for Action on Open Science” aims at increased openness and rapid, convenient and high-quality scientific communication – not just among researchers themselves but between researchers and society at large to bring huge benefits for science itself, as well as for its connection with society. Recently, the Council of the European Union agreed that all scientific papers should be freely available by 2020. Many universities, research institutions, and funding agencies are already imposing OA policies that require researchers to ensure OA to their research outputs, and more are likely to follow in the coming years.
SPE has largely been insulated from the OA movement, in part because so much of our literature is not driven by government-funded research. However, the society is beginning to get more requests to retain author rights or to allow OA to fulfill requirements from institutions funding research. After lengthy discussions, the SPE Board Committee on Communication and Knowledge Sharing has agreed to the following change in SPE’s policies to allow an option for OA for those authors that require it:
Personally, I strongly believe that science will have a bigger impact when there are no restrictions to access. Indeed, 20 years ago, while still a doctoral student at NTNU in Trondheim (Norway), I started an online preprint archive that still is operational. I therefore welcome the new SPE policy and encourage our authors to use the OA option if their paper is eligible.
This issue contains 30 papers, which I have organized into four categories. The first category comprises 13 papers on Enhanced Oil Recovery (EOR), including flooding with polymer, surfactant, and/or low-salinity water. The first paper by Fortenberry et al. discusses how detailed chemical simulations can be used to interpret the results of single-well partitioning-tracer tests run to evaluate EOR flood performance in one-spot pilots. In these tests, partitioning tracers are injected and back-produced twice to determine the difference in residual oil saturation after waterflooding and after chemical flooding.
The next two papers focus on phase behavior in systems containing surfactants. Lashgari et al. present a new method to couple compressible three-phase black-oil phase descriptions with surfactant-phase behavior on the basis of the classical Hand rule. Ghosh and Johns argue that models based on Hand’s rule have little predictive capability for the microemulsion behavior at different pressures, temperatures, and oil compositions, and propose a new model that combines the concept of hydrophilic/lipophilic differences with a net-average-curvature model.
Carbonate reservoirs are typically naturally fractured, and recovery from waterflooding is poor because water does not spontaneously imbibe into the oil-wet matrix rock. Surfactants can increase recovery by altering the rock from oil-wet to water-wet. The efficiency of this process relies on the contact area between the injected fluid and the matrix, which can be increased significantly if foam is used as a mobility-control agent. In the fourth paper, Singh and Mohanty report a systematic study of the effect of wettability alteration and foaming on tertiary oil recovery in oil-wet carbonate cores.
Fernø et al. investigate the generation of foam within carbonate fracture networks and study how this contributes to improve the sweep efficiency of surfactant-alternating-gas injection and coinjection of gas and surfactant. Likewise, Cui et al. discuss how a switchable surfactant (Ethomeen C12) can be used as a foaming agent to increase the sweep efficiency of CO2 flooding in high-temperature, high-salinity carbonate reservoirs. Then, Li et al. present a series of experiments showing how a mixture of hydrophilic anionic and cationic surfactants produce ultralow critical micelle concentrations, ultralow interfacial tension, and high oil solubilization, which all promote high tertiary oil recovery.
Obtaining sufficient injectivity is a concern for field application of polymer flooding. In the eighth contribution, Lotfollahi et al. develop a mechanistic model accounting for adsorption of polymer, shear-thickening behavior at high flow rates, filtering, and external filter-cake development. The authors use the new model to accurately assess injectivity and history match field data. The success of chemical EOR processes can also be affected strongly by reservoir heterogeneity, and in the ninth paper, Alkhatib and Babei develop a multilevel Monte Carlo method to quantify the effect of uncertainty in heterogeneity on the recovery factor for surfactant-polymer flooding.
The next papers are concerned with low-salinity flooding. Mugele et al. use high-resolution atomic-force microscopy to study the physicochemical processes that govern the competitive wetting of oil and water on reservoir rocks. Wettability alteration caused by these processes is believed to be a primary trigger in low-salinity waterflooding. Then, AlShaikh and Mahadevan study the effect of brine composition on wettability in carbonate reservoirs, and Sandengen et al. propose osmosis as a possible mechanism to explain the effects of low-salinity flooding, suggesting a critical reevaluation of spontaneous-imbibition tests, for which observed production could have stemmed from osmotic effects rather than wettability alteration, and also recommending a shift in research focus from sandstone reservoirs to fractured oil-wet carbonates.
The last paper by Kim et al. presents waterflood experiments set up to investigate the fact that waterflooding used to produce heavy and viscous oil is sometimes more efficient if the ratio of injected fluid to produced fluids at reservoir conditions is less than unity.
In the second category, we have 10 papers on Fracturing and Low-Permeability Reservoirs. The first three papers focus on modeling and surveillance of production from low-permeability reservoirs. In the first paper, Bajwa and Blunt develop a new semianalytical method for early-time production-forecasting before reservoir boundaries are encountered. The second contribution by Ribeiro and Horne discusses how temperature data obtained during and after the creation of fractures along a horizontal well can be used to not only identify which of the new fractures connects to a new reservoir zone, but also give the location of the zone. In the third paper, Norbeck and Horne investigate the physical mechanisms underlying microseismic depletion delineation, which is a surveillance technique used to identify the extent of depletion zones near production wells.
The next three papers are concerned with fracturing. Mighani et al. use the so-called Brazilian test to study fracturing in two groups of anisotropic rocks; in the first group, anisotropy is caused by mineral alignment, whereas the second group is characterized by the existence of calcite-filled veins. The fifth contribution by McClure et al. describes a hydraulic-fracturing simulator that couples fluid flow with stresses induced by fracture deformation in large, complex 3D discrete fracture networks. Then, in the next paper, McClure et al. use this simulator to study diagnostic fracture-injection tests, in which a fluid (water) is injected for a short period to create a relatively small fracture before the well is shut in. The authors present a new method to identify the closure pressure (i.e., the pressure at which fracture walls come into contact again after shut-in), and provide a theoretical justification for why the new method is better than other widely used methods.
Hull et al. discuss the use of viscoelastic surfactants as fracturing fluids and for azidizing carbonate-based reservoirs, whereas Esmaeilirad et al. present experiments that investigate to what extent dissolved organic matter in flowback and produced waters used in subsequent fracturing with gelled fluids will influence the success of the fracture treatment.
Fung and Du discuss a highly parallel simulation of gas recovery from shale reservoirs with ultralow permeability that is based on a multiconnected multicontinuum geological description combined with either a compositional or a black-oil fluid model, and in the last contribution, Chen et al. study depleted shale formations as possible candidates for CO2 storage and develop a new analytical method to estimate storage capacity.
The third category consists of four papers discussing various aspects of Reservoir Characterization and Reservoir Management. In the first paper, He et al. present a new work flow that aims to evaluate the effectiveness of data-acquisition programs before they are implemented. The second contribution by Chang et al. addresses the problem of preserving geological realism in ensemble-based data assimilation for channelized reservoirs. High-resolution imaging of reservoir rocks is usually combined with high-performance flow simulation to collect information on a sufficiently large scale to enable upscaling of transport properties. Then, Chen et al. discuss how graphics-processing units (GPUs) were used to accelerate one such computational method, the lattice Boltzmann method, while Chi and Heidari present a new model that incorporates directional pore-connectivity into models used to estimate permeability from nuclear magnetic resonance in carbonate formations with complex pore structures.
The last three papers have been grouped under the heading Drilling and Wells. The first paper by Chen et al. discusses azimuthal resistivity logging-while-drilling and presents an improved imaging theory that can be used to develop efficient and robust inversion methods. de Azevedo et al. present the development of a computational-fluid-dynamics model for transient two-phase flow within progressing-cavity pumps providing artificial oil lift, and finally, Hajidavalloo and Dehkohneh are concerned with crew safety during blowout. Flow tubes are usually installed above the wellhead to detach fire and provide working conditions for the operator team if a blowout oil/gas should catch fire. The authors present detailed simulations of a new type of perforated tube designed to reduce dangerous suction around the flow tube.
Recently, Emmanuel Detournay, Mingqin Duan, and Pingping Shen retired from the editorial board. I hereby thank them for the service they have provided to SPE and the readers of the journal. Likewise, let me welcome our new associate editors: Arild Saasen, Det norske oljeselskap AS; Clayton Deutsch, University of Alberta; Eric MacKay, Heriot-Watt University; and Ryosuke Okuno, University of Texas at Austin. Last, but not least, I wish to thank all the authors and reviewers of the 30 papers featured in this issue.