bluuebunny/crossref_metadata_2025_split huggingface dataset:
Implications of Shale Oil Compositions on Surfactant Efficacy for Wettability Alteration
Authors: Feng Lijie , Liang Xu 
Published: February 2021

Abstract
Surfactant selection is important for oil recovery in a hydraulically fractured reservoir. Two primary mechanisms, ion-pair coupling (cleaning) between surfactant and hydrocarbon and surfactant adsorption onto the rock surface (coating), were previously suggested to explain how surfactants can alter rock wettability, thus improving oil production. Because of the electrostatic interaction, acidic compounds in the oil tend to be adsorbed onto rock surface that is positively charged; whereas basic compounds are preferentially attracted to rock surface that is negatively charged. It has been discussed in previous literature that for wettability alteration for conventional formation rocks, the cleaning mechanism could be more efficient by inducing ion pairs between surfactants and oil compounds that have opposite charges, rather than the coating mechanism that mainly relies on how well surfactant covers the rock surface.
In this research, 90 shale oils from various liquids shale plays, such as the Eagle Ford and the Wolfcamp, were tested for total acid number (TAN) and total base number (TBN). Cationic and anionic surfactants with low interfacial surface tension, along with Berea sandstone and Indiana limestone, were used to investigate the extent that TAN and TBN can be used as criteria to select surfactants. Oil recovery, imbibition, interfacial surface tension, and emulsion tendency were conducted to examine whether the cleaning mechanism holds true for shale oil saturated formation rocks. The results demonstrated that for carbonates with shale oil having a higher TAN, a cationic surfactant provided the potential to sweep more oil than an anionic surfactant. On the other hand, for sandstone with shale oil having a higher TBN, an anionic surfactant performed better than a cationic surfactant. Those observations appear to be consistent with the proposed cleaning mechanism and resonate with production data for thousands of wells from some major liquids-rich shale plays.
The Fresh Water Neutral Challenge: The Need for Protection, Reduction, Innovation, and Conservation
Authors: Greaves R. , Hartstein R. , Lincicome D. , Wehner J. , Beck P. , Lamb J. , Olson K. 
Published: February 2021

Abstract
Southwestern Energy (SWN) is committed to being neutral in regard to the use of fresh water in our operations by 2016. This means that SWN will offset our fresh water footprint by reducing our fresh water usage and by replenishing any fresh water that we do use through conservation projects, which are designed to improve water quality and availability for the environment and communities around us. To meet this “fresh water neutral” commitment, the company launched the Energy Conserving Water (ECH2O) initiative in 2013.
Achieving ECH2O's goals centers on four key elements: 1) protection of water resources; 2) reduction of water used in our operations; 3) innovation to efficiently utilize alternative, non-fresh water sources; and 4) conservation to improve or replenish water resources.
SWN uses water in its operations every day, with the predominant usage for well stimulation through hydraulic fracturing. Our two largest operating divisions, the Fayetteville Shale and Marcellus Shale, use nearly 70 million barrels of water annually to hydraulically fracture over 500 wells. The fresh water use in these major areas, as well as smaller operating areas, and other operational uses of water are all included in the ECH2O imperative.
Numerical Investigation of Complex Hydraulic Fracture Development in Naturally Fractured Reservoirs
Authors: Kan Wu , Olson Jon E. 
Published: February 2021

Abstract
Complex fracture networks have become more evident in shale reservoirs due to the interaction between pre-existing natural and hydraulic fractures. Accurate characterization of fracture complexity plays an important role in optimizing fracturing design, especially for shale reservoirs with high-density natural fractures.
In this study, we simulated simultaneous multiple fracture propagation within a single fracturing stage using a complex hydraulic fracture development model. The model was developed to simulate complex fracture propagation by coupling rock mechanics and fluid mechanics. A simplified three-dimensional displacement discontinuity method was implemented to more accurately calculate fracture displacements and fracture-induced dynamic stress changes than our previously developed pseudo-3d model. The effects of perforation cluster spacing, differential stress (SHmax - Shmin) and various geometry natural fracture patterns on injection pressure and fracture complexity were investigated.
The single stage simulation results shown that (1) higher differential stress suppresses fracture length and increases injection pressure; (2) there is an optimal choice for the number of fractures per stage to maximize effective fracture surface area, beyond which increasing the number of fractures actually decreases effective fracture area; and (3) fracture complexity is a function of natural fracture patterns (various regular pattern geometries were investigated). Natural fractures with small relative angle to hydraulic fractures are more likely to control fracture propagation path. Also, natural fracture patterns with more long fractures tend to increase the likelihood to dominate the preferential fracture trend of fracture trajectory. Our numerical model can provide a physics-based complex fracture network that can be imported into reservoir simulation models for production analysis. The overall sensitivity results presented should serve as guidelines for fracture complexity analysis.
In-Situ Formation of Proppant and Highly Permeable Blocks for Hydraulic Fracturing
Authors: Chang Frank F. , Berger Paul D. , Lee Christie H. 
Published: February 2021

Abstract
Proppants are used to keep hydraulic fractures open, allowing for reservoir fluids to flow back after external pressure is withdrawn. Proppants are carried by the hydraulic fracturing fluid containing multiple components such as polymers, breakers, or friction reducing agent. These proppant systems have certain disadvantages such as formation and fracture permeability damage due to the viscous gel residue, risk of early screen-out and reduced effective propped area due to proppant excessive leakoff or settling, and abrasion to the pumping equipment and tubular.
Acid fracturing is another fracturing technique. It is used in carbonate reservoirs, in which the acid etches the fracture faces to create conductive path. The drawbacks of acid fracturing include short acid etch length due to rapid acid-carbonate rock reaction rate and corrosion to the tubular.
The oil and gas industry has been relying on these hydraulic fracturing techniques to proliferate production from low permeability reservoirs, and has made significantly advancement in tools and chemicals used in the fracturing processes. However, the maximized production and recovery is still unattainable due to the reasons mentioned above. This paper discusses a novel chemical compositions and process to overcome the challenges encountered by the current fracturing techniques. The goal is to convert injected fracturing fluid into a highly permeable proppant pack in-situ. Since the fracturing fluid itself forms the proppant, it can penetrate the entire fracture length, height, and complex network, maximizing the effective fracture area and stimulated reservoir volume. The rendered particle size can be significantly larger than conventional proppants without the concern of screen-out. The in-situ formed proppants have strength sufficient to resist fracture closure stress. In addition, no polymer is required to suspend the proppant; therefore no gel residue will be left to damage fracture conductivity.
Though it is in its preliminary development stage, interesting and encouraging test results have been obtained. Formulations, photos, and mechanical properties of in-situ generated proppants will be presented in this paper.
An Improved Equilibrium-Height Model for Predicting Hydraulic Fracture Height Migration in Multi-Layer Formations
Authors: Liu Songxia , Valkó Peter P. 
Published: February 2021

Abstract
Fracture height is a critical input parameter for 2D hydraulic fracturing design models, and also an important output result of 3D models. While many factors may influence fracture height evolution in multi-layer formations, the consensus is that the so called “equilibrium height belonging to a certain treating pressure” provides an upper limit, at least for non-naturally fractured media. How to solve the “equilibrium height” problem has been known since the 1970s. However, because of the complexity of the algebra involved, published equations are overly simplified and do not provide reliable results.
We revisited the equilibrium height problem, and our theoretical and numerical investigations led to a new model that fully characterizes height evolution amid various formation properties (fracture toughness, in-situ stress, thickness, etc.). The new model, for the first time, rigorously solves the equilibrium height mathematically. With the help of computer algebra software, we applied a definition of fracture toughness, incorporated the effects of hydrostatic pressure, and considered non-symmetric variations of layered formation properties. Results were determined for the classic 3-layer problem and then were extended to 6 layers.
The effects of reservoir and fluid properties on the fracture height growth were investigated. Tip jump is caused by low in-situ stress; tip stability is imposed by large fracture toughness and/or large in-situ stress. If the fluid density is ignored, the result regarding to which tip will grow into infinity could be totally different. For any multi-layer formation problem, two, 3-layer pseudo problems were constructed to create an outer and inner height envelope, in order to assess the potential effects of reservoir parameter uncertainties on height profile. Second solution pair in the 3-layer problem was investigated numerically and analytically, to avoid misleading results in the 3D models.
This improved model can rapidly (in seconds) and reliably calculate the theoretical maximum equilibrium fracture height in layered formations with various rock mechanical properties. Then, the equilibrium height can be used to (1) provide input data for 2D model, (2) improve 3D model governing equations, (3) determine the net pressure needed to achieve a certain height growth, and (4) obtain the maximum net pressure assuring no fracture invasion into aquifers. This model may be incorporated into current hydraulic fracture simulation software to yield more accurate and cost-effective hydraulic fracturing designs.
A Case History: Evaluating Well Completions in the Eagle Ford Shale Using a Data-Driven Approach
Authors: Nejad Amir M. , Sheludko Stanislav , Shelley Robert F. , Hodgson Trey , McFall Riley 
Published: February 2021

Abstract
Unconventional shale resources are key hydrocarbon sources, gaining importance and popularity as hydrocarbon reservoirs both in the United States and internationally. Horizontal wellbores and multiple transverse hydraulic fracturing are instrumental factors for economical production from shale assets. Hydraulic fracturing typically represents a major component of total well completion costs, and many efforts have been made to study and investigate different strategies to improve well production and reduce costs. The focus of this paper is completion effectiveness evaluation in different parts of the Eagle Ford Shale Formation, and our objective is to identify appropriate completion strategies in the field.
A data-driven neural network model is trained on the database comprised of multiple operators' well data. In this model, drilling and mud data are used as indicators for geology and reservoir-related parameters such as pressure, fluid saturation and permeability. Additionally, completion- and fracture-related parameters are also used as model inputs. Because wells are pressure managed differently, normalized oil and gas production is used as a model output. Thousands of neural networks are trained using genetic algorithm in order to fully evaluate hidden correlations within the database. This results in selection of a neural network that is able to understand reservoir, completion and frac differences between wells and identify how to improve future completion/stimulation designs.
The final neural network model is successfully developed and tested on two separate data sets located in different parts of the Eagle Ford Shale oil window. Further, an additional test data set comprised of eight wells from a third field location is used to validate the predictive usefulness of the data-driven model. Under-producing wells were also identified by the model and new fracture designs were recommended to improve well productivity.
This paper will be useful for understanding the effects of completion and fracture treatment designs on well productivity in the Eagle Ford. This information will help operators select more effective treatment designs, which can reduce operational costs associated with completion/fracturing and can improve oil and gas production.
What is More Important for Proppant Transport, Viscosity or Elasticity?
Authors: Hu Y. Thomas , Chung HsinChen , Jason Maxey 
Published: February 2021

Abstract
The contributions of viscosity and elasticity to inhibiting proppant settling in gelled fracturing fluids are quantified and decoupled in this study. The settling velocity of a single particle under orthogonal shear flow was measured in a transparent Couette flow cell using automatic particle tracking, and the local flow field was mapped using particle tracking velocimetry. The settling behavior is correlated with the rheological properties of the fluids.
In carboxymethyl hydroxypropyl guar (CMHPG) crosslinked with borate, particle settling slows as the orthogonal shear rate increases, with settling essentially stopping at sufficiently high shear rates. The authors propose that there are two primary mechanisms for the enhanced particle suspending under the orthogonal shear—shear thickening and elastic lifting. The relative importance of the two factors depends on the shear rate and fluid relaxation time. Specifically, the ratio of the elastic and viscous contribution to particle suspension is γe/v=0.5cλN1(γ˙)η(γ˙), where c is a constant, λ is the stress relaxation time, N1(γ˙)) is the first normal stress difference that depends on the shear rate γ˙, and η(η(γ˙)) is the viscosity.
For the crosslinked CMHPG gel examined in this work, it is determined that γe/v=0.26γ˙2, indicating that the viscosity is more important at γ⋅&lt;2s−1, whereas the elasticity becomes dominant at γ˙&lt;2 s−1 for proppant suspending. For the uncrosslinked CMHPG, γe/v=0.0035γ˙1.3 , indicating that the elastic contribution becomes more important than the viscous contribution only at shear rates &gt; 80 s−1. The understanding of the relative importance of viscosity and elasticity can provide guidance for chemists to develop better fracturing fluids and for engineers to model proppant transport
Application of Extended Finite Element Method (XFEM) to Simulate Hydraulic Fracture Propagation from Oriented Perforations
Authors: Sepehri Jay , Soliman Mohamed Y. , Morse Stephen M. 
Published: February 2021

Abstract
Understanding fracture initiation and propagation from perforated wellbores is essential to designing a perforation scheme to achieve an efficient hydraulic fracture stimulation treatment. The effect of perforation design on hydraulic fracture propagation has been extensively studied using experimental and analytical methods. Because the experimental investigation of hydraulic fracture is complicated, expensive, and often returns limited results, numerical methods can be applied as an efficient way to simulate fracture propagation from perforations. An Extended Finite Element Method (XFEM) was used to develop a model to investigate the effects of various parameters on fracture propagation from a set of perforations. These parameters included perforation orientation, perforation length, stress anisotropy, and elastic properties of the formation. Fracture propagation patterns from the XFEM model were first matched against published experimental studies and exhibited good agreement. The model was then used to broaden the study of perforation effects. Results of the modeling proved the effects of perforation orientation and length on hydraulic fracture propagation pattern. Horizontal stress anisotropy and rock mechanical properties were observed to strongly influence fracture propagation. It was also observed that, when two or more perforations are positioned at different orientation angles at the same depth, a fracture tends to propagate from the less deviated perforation. In these cases, the more deviated perforation can develop a short fracture, following a propagating pattern that could be caused by stress shadowing/interference. Stress interference between two perforations positioned closely together results in either perforation breakdown or fracture propagating away from one another. The simulation results from this study offer methods to enhance perforation design for hydraulic fracture treatment, particularly in the case of high stress anisotropy and high uncertainty in a preferred fracture plane. Analyzing competing perforations suggests that a technique based on this concept can be applied when high uncertainty exists regarding the direction of the principal horizontal stresses through increasing perforation density.
The Third Dimension: Productivity Effects From Spatial Placement and Well Architecture in Eagle Ford Shale Horizontal Wells
Authors: Holcomb William , LaFollette Randy F. , Zhong Ming 
Published: February 2021

Abstract
Eagle Ford shale formation exhibits highly variability hydrocarbon production rates and EUR within small areas, indicating a highly heterogeneous reservoir. Attempts to determine performance drivers among geological, production or completion data points have produced inconclusive results. For example, production for one cluster of nearby wells may be strongly correlated with proppant quantity, while the trend is not valid for a group of similar wells a short distance away. A more widely valid set of correlations could improve engineering efficiency and productivity across the play.
Multivariate statistical modeling has indicated that wellbore architecture factors influence well performance. Such models have determined relative influence of such factors as fracturing fluid type and volumes, proppant sizes and volumes, etc. On the wellbore architecture side, prior studies found that surface latitude and longitude are among the strongest drivers. However, these studies largely omitted consideration of the third dimension (relative vertical location in the reservoir).
This study evaluates productivity influences from azimuth, dip, porpoising, and TVD from heel to toe (vertical zone coverage). It also reconsiders previously studied factors (such as fracturing fluids and proppants) with a considerably larger body of data—especially longer-term production data—than was available for the prior studies. The goal is to determine geological, wellbore architecture, and completion factors that show statistical significance as performance drivers, and where they are applicable if the results vary across the play.
Field Determination of Fracture Propagation Mode Using Downhole Pressure Data
Authors: Daneshy Ali , Touchet Chad , Hoffman Fred , McKown Mike 
Published: February 2021

Abstract
This paper presents the analysis results of 60 single stage fracturing treatments performed in a horizontal well using cemented casing sleeves and a coiled tubing deployed frac isolation system as the completion method. In this carefully set-up and executed treatment, separation between the toe stages was 97 feet, and near the heel it was 55 feet. Pressure data was collected above and below the retrievable plug used for stage isolation. This data was used for analysis of fracturing treatment data which included mode of propagation, completion efficiency, and a rough estimate of fracture orientation. The analysis showed that; There was no interaction between adjacent fractures during five of the sixty fracturing stages. None of these was in the well interval with shorter fracture spacingFracture shadowing occurred during six fracture stages, again none in the shorter spacing intervalMinor cement defects (micro-annuli) caused some fluid migration into the passive segment of the well. This happened in 27 stages. Of these; In eleven cases the cement defects were plugged after a while, causing the migration of fracturing fluid into the passive interval to stop.In sixteen other cases the fluid migration through cement micro-annuli continued during fracturing.During ten stages, defective zone isolation and fluid migration caused a pressure increase of several hundred psi in the passive segment of the well. But this did not result in extension of passive fractures.The volume of migrated slurry due to inadequate zone isolation was mostly a very small fraction of the injected volume.During five stages poor cement quality hampered stage isolation and caused immediate link between adjacent active and passive intervals and extension of passive fractures.The data indicate possible connection between the active and one passive fracture in four stages.Shorter spacing between stages increased the incidents of fluid migration due to poor cement qualityThe fracturing pressure variations during the treatments did not indicate presence of large stress shadowingA rough estimation of fracture orientation indicates that they were likely to be vertical and nearly perpendicular to the wellbore.The fracture growth pattern can best be described as off-balance.
To our knowledge, this is the first time existence of direct communication between adjacent fractures has been observed through actual pressure interference data.