bluuebunny/crossref_metadata_2025_split huggingface dataset:
Interfacial Viscoelasticity of Crude Oil/Brine: An Alternative Enhanced-Oil-Recovery Mechanism in Smart Waterflooding
Authors: Bidhendi Mehrnoosh Moradi , Garcia-Olvera Griselda , Morin Brendon , Oakey John S. , Alvarado Vladimir 
Published: January 2018

Summary
Injection of water with a designed chemistry has been proposed as a novel enhanced-oil-recovery (EOR) method, commonly referred to as low-salinity (LS) or smart waterflooding, among other labels. The multiple names encompass a family of EOR methods that rely on modifying injection-water chemistry to increase oil recovery. Despite successful laboratory experiments and field trials, underlying EOR mechanisms remain controversial and poorly understood. At present, the vast majority of the proposed mechanisms rely on rock/fluid interactions. In this work, we propose an alternative fluid/fluid interaction mechanism (i.e., an increase in crude-oil/water interfacial viscoelasticity upon injection of designed brine as a suppressor of oil trapping by snap-off). A crude oil from Wyoming was selected for its known interfacial responsiveness to water chemistry. Brines were prepared with analytic-grade salts to test the effect of specific anions and cations. The brines’ ionic strengths were modified by dilution with deionized water to the desired salinity. A battery of experiments was performed to show a link between dynamic interfacial viscoelasticity and recovery. Experiments include double-wall ring interfacial rheometry, direct visualization on microfluidic devices, and coreflooding experiments in Berea sandstone cores. Interfacial rheological results show that interfacial viscoelasticity generally increases as brine salinity is decreased, regardless of which cations and anions are present in brine. However, the rate of elasticity buildup and the plateau value depend on specific ions available in solution. Snap-off analysis in a microfluidic device, consisting of a flow-focusing geometry, demonstrates that increased viscoelasticity suppresses interfacial pinch-off, and sustains a more continuous oil phase. This effect was examined in coreflooding experiments with sodium sulfate brines. Corefloods were designed to limit wettability alteration by maintaining a low temperature (25°C) and short aging times. Geochemical analysis provided information on in-situ water chemistry. Oil-recovery and pressure responses were shown to directly correlate with interfacial elasticity [i.e., recovery factor (RF) is consistently greater the larger the induced interfacial viscoelasticity for the system examined in this paper]. Our results demonstrate that a largely overlooked interfacial effect of engineered waterflooding can serve as an alternative and more complete explanation of LS or engineered waterflooding recovery. This new mechanism offers a direction to design water chemistry for optimized waterflooding recovery in engineered water-chemistry processes, and opens a new route to design EOR methods.
RAND-Based Formulations for Isothermal Multiphase Flash
Authors: Paterson Duncan , Michelsen Michael L. , Stenby Erling H. , Yan Wei 
Published: January 2018

Summary
Two algorithms are proposed for isothermal multiphase flash. These are referred to as modified RAND and vol-RAND. The former uses the chemical potentials and molar-phase amounts as the iteration variables, while the latter uses chemical potentials and phase volumes to cosolve a pressure-explicit equation of state (EOS) with the equilibrium equations. Compared with the conventional second-order approach using Gibbs-energy minimization, these methods are more structured, with all components in all phases treated in the same way. Both have been derived to include chemical reactions for any number of phases along with the possible simplifications for only phase equilibria. The simple structured implementation of these methods is demonstrated for modified RAND and vol-RAND. The rate of convergence of the methods presented is shown to be the same as the conventional second-order method for isothermal flash. It is demonstrated that the use of an association term [cubic plus association (CPA)] adds little additional computational cost when using vol-RAND compared with a simple cubic Soave-Redlich-Kwong (SRK) without association. The RAND methods scale better in terms of the O(n3) operations as more phases are introduced, and are computationally less expensive than the conventional Gibbs minimization method for more than three phases.
Reinterpretation of Flow Patterns During DFITs Based on Dynamic Fracture Geometry, Leakoff and Afterflow
Authors: Zanganeh Behnam , Clarkson Christopher R. , Jones Jack R. 
Published: January 2018

Abstract
The goal of this study is to explain the full spectrum of flow patterns observed before and after closure during diagnostic fracture injection tests (DFITs) by considering the dynamic nature of fracture geometry, variable leakoff rate and afterflow volume caused by wellbore storage.
A fit-for-purpose simulation model is used to simulate DFITs and generate pressure responses in low-permeability (tight) reservoirs. The cohesive zone model in Abaqus® is used to simulate hydraulic fracture propagation and closure. A customized leakoff model incorporated into the software accounts for variable leakoff rate as a function of reservoir properties, fracture pressure, fracture surface area and exposure time. The afterflow is modeled by including a wellbore volume and accounting for wellbore storage. Results are compared to field data to explain the full spectrum of flow patterns and fracture dynamics observed in pressure transient analysis of DFITs.
The overall falloff period is interpreted, using PTA diagnostic plots, for relative magnitudes of afterflow, leakoff rate and fluid flow in the formation. Initially, afterflow is high, resulting in fracture expansion, which is characterized by a unit slope on the Bourdet-derivative plot. The afterflow does not necessarily end after the unit slope terminates; the end of fracture expansion is signaled by a characteristic hump on the derivative plot. During fracture expansion, the afterflow decreases and the leakoff rate increases due to the larger fracture area. When the leakoff rate dominates over afterflow, fracture closure mechanics can be conceptualized as a moving hinge-closure, where the fracture volume reduces, and fracture tip extension occurs as fluid is pushed to the tip of fracture (indicated by fluctuations in the derivative). The transition from afterflow to leakoff dominance and the moving hinge-closure manifest as a semi-horizontal trend on the Bourdet-derivative. Subsequently, a progressive fracture closure occurs gradually along the fracture, identified by an increasing trend or a sharp decline on the primary pressure derivative, depending on the conductivity. Different estimates of closure pressure will be obtained early and late in this process. The pressure behavior immediately after full closure is observed to be affected by the residual leakoff and the continuing afterflow. Once all of these fracture, wellbore and leakoff processes are abated, the reservoir response is observed.
This study provides a clear understanding of the different mechanisms affecting pressure behavior during DFITs for tight reservoirs in order to arrive at more reliable estimates of fracturing parameters and reservoir properties. As an example, mechanisms leading to false before- and after-closure radial flow identification are explained.
Estimating Unpropped Fracture Conductivity and Compliance from Diagnostic Fracture Injection Tests
Authors: Wang HanYi , Sharma Mukul M. 
Published: January 2018

Abstract
A new method is proposed to estimate the compliance and conductivity of induced unpropped fractures as a function of the effective stress acting on the fracture from DFIT data. A hydraulic fracture's resistance to displacement and closure is described by its compliance (or stiffness). Fracture compliance is closely related to theelastic, failure and hydraulic properties of the rock. Quantifying fracture compliance and fracture conductivity under in-situ conditions is crucial in many earth science and engineering applications but very difficult to achieve. Even though laboratory experiments are often used to measure fracture compliance and conductivity, the measurement results are strongly influenced by how the fracture is created, the specific rock sample obtained andthe degree to which it is preserved. As such the results may not be representative of field scale fractures
Over the past two decades, Diagnostic Fracture Injection Tests (DFIT) has evolved into a commonly used and reliable technique to obtain in-situ stresses, fluid leak-off parameters and formation permeability. The pressure decline response across the entire duration of a DFIT test reflects the process of fracture closure and reservoir flow capacity. As such it is possible to use this data to quantify changes in fracture conductivity as a function of stress. In this paper we presenta single, coherent mathematical framework to accomplish this. We show how each factor impacts the pressure decline response and the effects of previous overlooked coupled mechanisms are examined and discussed. Synthetic and field case studies are presented to illustrate the method. Most importantly,a new specialized plot (normalized system stiffness plot) is proposed, which not only providesclear evidence of the existence of a residual fracture width as afracture is closing during a DFIT, but also allows us to estimate fracture compliance (or stiffness) evolution and infer un-propped fracture conductivity using only DFIT pressure and time data based on a time-convolution solution. It is recommended that the normalized system stiffness plot be used as a standard practice to complement the G-function or square root of time plotbecause it provides veryvaluable information on the properties of fracture surface roughness at a field-scale, information that cannot be obtained by any other means.
Impact of near Well-Bore Geology on Hydraulic Fractures Geometry and Well Productivity: A Statistical Look Back at the Utica Play
Authors: Gourjon Emeric , Bertoncello Antoine 
Published: January 2018

Abstract
It is common in unconventional plays to have offset wells with very different productivity, even though these wells were drilled at the same time, in the same landing zone and with the same completion design. Such well behaviour is always puzzling because subsurface properties are not expected to vary significantly at a small scale.
This problem has been identified in several pads in the Utica play. To try to understand this phenomena, a geological and statistical analysis has been performed on more than 400 wells and 7000 stages. The results show that differences between offset wells occur mainly when the two wells have their stages placed in slightly different facies. More precisely, we show that within a 40 feet thick landing zone, stages can be placed in 3 types of facies: (a.) facies A with a gamma-ray (GR) of ~70°API (~40% Vclay), (b.) facies B with a GR of ~60°API (~20% Vclay) and (c.) Facies C with a GR of ~50°API (~5% Vclay). Generally, for a given well, if more than 50% of its stages are in facies A, the production is 15% lower than a well with no stages in facies A.
Analysis of pressure data from completion indicate that the productivity decrease originates from limited fractures propagations when the completion is initiated in the clay-rich facies. Stages completed in facies A show a high near well-bore pressure loss and a low net pressure, which is consistent with the notion of shale choke, where fracture propagation is limited to the near well-bore. On the contrary, stages placed in the brittle facies C show high net pressures and low near well bore pressure losses, consistent with well- developed fracture geometry in the far-field. This difference in hydraulic fracture geometry could explain the difference in production between two neighboring wells.
Such results are important because it shows that stage placement is critical to productivity, even when the well has been accurately geosteered in the target zone. Optimizing the completion design by accounting for the heterogeneities should therefore significantly improve productivity and guide operation strategy.
Analysis and Modeling of Proppant Transport in Inclined Hydraulic Fractures
Authors: Kou R. , Moridis G. J. , Blasingame T. A. 
Published: January 2018

Abstract
The understanding of proppant transport in fractures plays a critical role in estimating propped fracture dimensions and performance. Modeling of such processes is challenging because of the complex interactions between fluid, proppant particles and fracture geometry. Existing models generally assume vertical planar fracture geometry, whereas the reality in the subsurface maybe much more complex. In this study we use discrete element method and computational fluid dynamics simulations to demonstrate that interactions between proppant particles and fracture side walls play an important role in proppant transport efficiency.
To calibrate our numerical model, we conducted two validation simulations that describe particle settling tests and laboratory proppant transport experiments. Through scoping calculations, we determined the correct drag force model and matched both analytical solutions and experimental data for a wide range of flow regimes. We then constructed two hydraulic fracture simulation domains, one with a vertical planar fracture (as a base case), and the other with an inclined planar hydraulic fracture. In the main component of our study, we conducted proppant transport simulations using our benchmarked models in both domains and compared the proppant distribution results.
By analyzing the velocity and trajectory of proppant particles during transport, we identified two different stages of the proppant transport process - a "suspension" stage and a "settling" stage. During the suspension stage, fluid drag and gravitational forces dominate, driving proppants further into the fracture. When the proppants collide with existing proppants dunes, the proppant particles lose momentum and become "settled." Our results show that settled proppant are more difficult to be mobilized by fluid drag force, for the reason that kinetic energy is easily dissipated inside proppant dunes. Finally, we observed that proppant settles slower in inclined planar fractures, due to the supporting force from fracture side walls cancelling part of the gravitational force which act on the particle. This leads to a better proppant placement efficiency in inclined fractures.

Objectives
The objective of this work is to provide a better understanding of proppant transport behavior in inclined planar fractures by means of numerical simulation. A significant difference from prior (laboratory) experiments is the capability of our model to simulate proppant transport at field-scale flowrates. Such acapability is critical in understanding proppant transport and appropriately designing it by ensuring that the correct Reynolds number and flow regime are used in the design calculations.
Demonstration of Proof of Concept of Electromagnetic Geophysical Methods for High Resolution Illumination of Induced Fracture Networks
Authors: Ahmadian Mohsen , LaBrecque Douglas , Liu Qing Huo , Slack William , Brigham Russell , Fang Yuan , Banks Kevin , Hu Yunyun , Wang Dezhi , Zhang Runren 
Published: January 2018

Abstract
In April 2017, the Advanced Energy Consortium (AEC) successfully completed data collection for a proof-of-concept demonstration of remote mapping of hydraulically fractured networks using electromagnetic (EM) proppant additives and a variety of EM tools and configurations.
This field-pilot demonstration was conducted at the Devine Test Site, located approximately 50 miles southwest of San Antonio, Texas, and managed by the Bureau of Economic Geology (Bureau) at The University of Texas at Austin. The objective of the ongoing integrated research program is to develop a remote EM-imaging technique for hydraulically fractured networks in order to obtain a higher-resolution image of proppant distribution (lateral/vertical extent and azimuth), which current technologies, such as microseismic, do not allow. The current study is a more in-depth follow-up to a series of shallow field tests that the AEC conducted in 2015 near Clemson University in South Carolina. This paper details the special aspects of the Devine Test Site that make it a unique asset for benchmarking EM-based hydraulic-fracture mapping tools and models.
Results from the Devine Test Site demonstrate that a measurable and noticeable EM anomaly was detectable with both time-domain and frequency-domain induced polarization methods. EM- inversion results were consistent with analysis of surface tiltmeter results but diverged significantly from passive seismic responses obtained during the hydraulic-fracturing process. The site will be cored at multiple locations over the next few months, after which accuracy of models and methods will be validated. Future opportunities for collaboration on this highly validated benchmarked site are discussed.
Developing Guidelines for Selection of Appropriate Fracture Models in the Numerical Simulation of Well Performance Behavior for Liquid Rich Ultra-Low Permeability ULP Reservoirs
Authors: Sivon A. G. , Moridis G. J. , Blasingame T. A. 
Published: January 2018

Abstract
The numerical prediction of production from stimulated Ultra-Low Permeability (ULP) media is highly correlated with the type of fracture model used in the simulator. Although there are some general rules about the applicability of these fracture models, there are no guidelines for the a-priori selection of an appropriate model — generally, the fracture model is selected based on the preference and/or familiarity of the person performing the modeling, rather than some "more technical" criteria. In that light, this work presents an effort to provide guidance for fracture model suitability for cases from the Eagle Ford, Bakken, Three Forks, and Wolfcamp formations.
In this work, production data from multiple wells in the aforementioned reservoirs are history-matched using models commonly available in commercial reservoir simulators. We evaluate the ability of the equivalent continuum model (ECM), the dual porosity, the dual permeability, and the multiple interactive continuum model (MINC) to represent these wells.
We determine that a correlation exists between the choice of the fracture model and the reservoir. However, the results of the study do not provide a sufficiently strong indication of model superiority which would support authoritative guidelines about applicability for a particular reservoir. Ultimately the choice of the most representative model depends on the particular well. The proposed recommendationsprovide guidance onthe appropriate fracture model to represent the studied reservoirs, thus enhancing their usefulness in the completion design process and the evaluation and prediction of production.
Stimulation Design and Treatment in the Sycamore Formation of the South Central Oklahoma Oil Province Area of the Anadarko Basin
Authors: Jackson James , Calvin James , Drake Brandon 
Published: January 2018

Abstract
The South Central Oklahoma Oil Province (SCOOP) and the Sooner Trend, Anadarko, Canadian, and Kingfisher (STACK) play areas of the Anadarko basin continue to grow and gain prominence. Perhaps the two most widely known formations in these areas are the Meramec and Woodford Shale; however, other formations also contain hydrocarbon potential. The objective here is to present an overview of the Sycamore formation and associated treatment design and discuss production analysis.
As development continues in both the SCOOP and STACK areas, more formations, such as the Sycamore, are being explored. Currently, development of this formation has been limited and minimal research has been published about this formation in recent years. Operators are now beginning to consider it for potential development for horizontal completions; therefore, it is important to develop a better reservoir understanding to apply appropriate technologies and more effectively complete wells drilled in this formation. Through analysis of studies conducted in the area of interest and data gathered about the formation, an appropriate stimulation treatment was formulated.
This paper discusses using several technologies, such as diversion and microproppant, in the fracture stimulation designs and the resulting impact on production for a well drilled in the Sycamore formation in Grady County, Oklahoma in the SCOOP area. The stimulation designs' components and technologies used were selected based on an understanding of the area. Successful completion techniques used in other formations were also incorporated into the stimulation designs. The production results from this particular well example are encouraging and are among the best in the area. The well's performance demonstrates the high degree of potential of the Sycamore formation.
This paper provides an overview of the Sycamore formation, completion and treatment design analyses, technologies used, petrophysical and formation evaluation studies conducted in the area, production analysis, and associated numerical and analytical modeling.