bluuebunny/crossref_metadata_2025_split huggingface dataset:
Investigation of Rupture and Slip Mechanisms of Hydraulic Fractures in Multiple-Layered Formations
Authors: Tang Jizhou , Wu Kan , Zuo Lihua , Xiao Lizhi , Sun Sijie , Ehlig–Economides Christine 
Published: August 2019

SummaryWeak bedding planes (BPs) that exist in many tight oil formations and shale–gas formations might strongly affect fracture–height growth during hydraulic–fracturing treatment. Few of the hydraulic–fracture–propagation models developed for unconventional reservoirs are capable of quantitatively estimating the fracture–height containment or predicting the fracture geometry under the influence of multiple BPs. In this paper, we introduce a coupled 3D hydraulic–fracture–propagation model considering the effects of BPs. In this model, a fully 3D displacement–discontinuity method (3D DDM) is used to model the rock deformation. The advantage of this approach is that it addresses both the mechanical interaction between hydraulic fractures and weak BPs in 3D space and the physical mechanism of slippage along weak BPs. Fluid flow governed by a finite–difference methodology considers the flow in both vertical fractures and opening BPs. An iterative algorithm is used to couple fluid flow and rock deformation. Comparison between the developed model and the Perkins–Kern–Nordgren (PKN) model showed good agreement.I–shaped fracture geometry and crossing–shaped fracture geometry were analyzed in this paper. From numerical investigations, we found that BPs cannot be opened if the difference between overburden stress and minimum horizontal stress is large and only shear displacements exist along the BPs, which damage the planes and thus greatly amplify their hydraulic conductivity. Moreover, sensitivity studies investigate the impact on fracture propagation of parameters such as pumping rate (PR), fluid viscosity, and Young's modulus (YM). We investigated the fracture width near the junction between a vertical fracture and the BPs, the latter including the tensile opening of BPs and shear–displacement discontinuities (SDDs) along them. SDDs along BPs increase at the beginning and then decrease at a distance from the junction. The width near the junctions, the opening of BPs, and SDDs along the planes are directly proportional to PR. Because viscosity increases, the width at a junction increases as do the SDDs. YM greatly influences the opening of BPs at a junction and the SDDs along the BPs. This model estimates the fracture–width distribution and the SDDs along the BPs near junctions between the fracture tip and BPs and enables the assessment of the PR required to ensure that the fracture width at junctions and along intersected BPs is sufficient for proppant transport.
Catalytic-Effect Comparison Between Nickel and Iron Oxide Nanoparticles During Aquathermolysis-Aided Cyclic Steam Stimulation
Authors: Yi Siyuan , Babadagli Tayfun , Li Huazhou Andy 
Published: August 2019

Summary
Cyclic steam stimulation (CSS) is a proven effective technique for boosting oil production. Metal species can act as a catalyst for aquathermolysis reactions between heavy oil and water during the CSS process. For this paper, a series of CSS experiments with and without metal nanoparticles was conducted at temperatures up to 220°C to compare the performance of nickel and iron oxide nanoparticles in promoting aquathermolysis reactions in CSS; further, different loadings of metal nanoparticles were also tested in the CSS experiments. During the experiments, we monitored the variations of oil recovery factor, oil viscosity, gas composition, and water production. The experimental results show that both nickel and iron oxide nanoparticles can act as a catalyst for aquathermolysis reactions and reduce the viscosity of heavy oil. However, their respective catalytic effects differ significantly: nickel nanoparticles can break the C-S bond more effectively than iron oxide metal nanoparticles, thus achieving a higher ultimate oil recovery factor of CSS. The introduction of metal nanoparticles boosted oil production and increased water production from the very first cycle in the CSS process. The gas chromatography (GC) analysis and the pressure data recorded during each soaking period revealed that a higher amount of evolved gas including alkenes and hydrogen sulfide was generated in the early stage, increasing reservoir pressure and forcing more condensed water to be produced from the sandpack.
Experimental Study of Surfactant-Assisted Oil Recovery in the Middle Bakken Cores
Authors: Zhang Shaojie , Li Chuncheng , Pu Hui , Ling Kegang , Sun Runxuan , Zhao Julia Xiaojun 
Published: August 2019

Abstract
In this study, six core samples were obtained from the Middle Bakken Formation in North Dakota. Before the imbibition experiment, petrophysical analysis were conducted for the samples. XRD method was used to analyze the mineral composition. Nitrogen adsorption and SEM methods were combined to study the pore size distribution and microstructures. Then the authors performed brine imbibition and surfactant imbibition for six Bakken cores and two Berea sandstones. Before the experiment, the cores were fully filled with Bakken crude oil. The core plugs were then submerged into the brine and surfactant solutions with all-face-open (AFO) condition. Experiments of brine and surfactant imbibing into oil-filled cores were carried out with recording of recovered oil volume using imbibition cells. Different types of surfactants such as cationic, anionic, and nonionic, were tested in the study. Those experiments evaluate the oil displacement efficiencies of brine and different surfactants in Bakken rocks.
Descriptive Data Analytics to Investigate Stimulation and Completion Trends in the United States: How Proppant and Water Utilization have Changed over Time?
Authors: Al-Alwani Mustafa A. , Britt Larry K. , Dunn-Norman Shari , Alkinani Husam H. , Al-Hameedi Abo Taleb , Salem Ebrahem , Al-Attar Atheer M. , Al-Bazzaz Waleed H. 
Published: August 2019

Abstract
The United States hydraulic fracturing and completion activities have seen a paradigm shift in the pumped water and proppant volumes along the increasing completed lateral over time. Hydraulic fracturing has become the most dominant treatment in North America to tap the unconventional resources. Large scale analysis of the completion size in terms of the amount of proppant, water, and lateral length trends over the period of 2011 and 2018 is presented in this paper. The objective of this study is to elucidate the completion trends over time and to summarize the average values of the completion and stimulation parameters. It will put the readers’ mind in perspective of how much proppant and water have been utilized over the years and shine a light on the progression of the industry growing demand on water and proppant.
Data from FracFocus website, which serves as an official chemical disclosure registry for many of the oil and gas states, were utilized in this study. For each stimulated well, it reports water volume and mass percentage of proppant and all other chemical ingredients. The raw data were scraped, parsed, and cleaned using advanced statistical and validation approaches to extract useful information out of the noisy data. A database of more than 80,000 wells was built and integrated into this study. Proppant total mass and the concentration of other chemical ingredients were calculated. The obtained new variables were coupled with other completion parameters such as the horizontal length, perforated lateral length, and well types.
The data of each parameter were subjected to rigorous quality control and inspected for outliers. After passing all the data quality and validation procedures, an advanced data visualization technique was selected to reflect the trends over time. The overall trends of the whole aggregated United States are presented in this paper. Investigating the created visualizations showed that there is an undeniable increasing trend in the amount of the proppant and water being consumed over the investigated period.
This paper exploits a large number of wells and their associated parameters. Such a large dataset will provide a comprehensive and practical representation of the completion and stimulation trends. It will also establish a baseline and reference values for the investigated parameters by benchmarking the mean, median, and other statistical expressions for each time period.
Sand Transport, Does Viscosity Matter?
Authors: Galindo Tanhee 
Published: August 2019

Abstract
The ability to effectively transport sand without the use of guar-based fluids has led to the development of friction reducers that build viscosity. These new products, also known as high viscosity friction reducers (HVFR) generate viscosities comparable to or greater than linear gel fluids. The selection criteria have focused primarily on achieving greater than 10 cP at 300 RPM (511s-1). As the salinity of the base fluid changes, the HVFR dosages must be increased up to 4X to meet this target. However, there is limited data available on how this viscosity correlates to the fluid’s ability to transport sand. This study presents methodology used to screen HVFR’s in various fluids and results on product performance, which identifies need for alternative specifications to viscosity.
The sand transport capacity under dynamic conditions was evaluated for two commercially available HVFR’s in up to 120,000 TDS synthetic water. A slot flow apparatus was used to mimic fluid flow through a fracture under different shear and flow conditions. The viscosity and elasticity were also measured using an advanced rotational rheometer. For comparison, a linear gel fluid was also evaluated.
While viscosity targets can be achieved by many commercially available HVFR products in freshwater, when salinity is increased, these products fail to meet the same targets. A comparison of the viscosity versus the sand transport capacity of these fluids, suggests viscosity does not indicate sand carrying capacity. The author did not find a correlation between higher viscosity and better sand transport. The results provided insight into the effect of flow rate on sand transport. The effect of salinity on s and transport suggests good performance can be achieved even at low viscosity. Elasticity testing of those same products suggested that HVFR’s have a critical elasticity range at which they will provide optimal performance.
This paper provides insight into the HVFR properties which correlate to sand transport and highlights the need for development of standardized test criteria other than viscosity. Further testing and screening of HVFR’s will increase the understanding of key factors influencing sand transport.
Quantifying the Impact of Fracturing Chemicals on Production Performance Using Machine Learning
Authors: Rastogi Ayush , Sharma Akash 
Published: August 2019

Abstract
Completion design is widely considered as a dynamic area of experimentation and development due to its significant impact on production performance in unconventional reservoirs. As the industry moves beyond the paradigm of proppant and base fluid analysis, more and more focus is being given to the composition of chemicals being used in the completion design. This paper focuses on quantifying the true impact of these chemicals used in completion design by using machine learning to solve this multivariable problem and creates value by providing a framework to help completion engineers select the optimum chemicals and aid in fracture treatment design process, using a data-driven approach.
Depending on the shale formation being fractured, a typical fracture treatment job uses a very low concentration of 3-12 additive chemicals. This selection is carried out from thousands of commercially available chemicals and is based on treatment job performance carried out during the modeling phase as well as from field experience. In this work the authors have tried to deconstruct the varied chemical groups used in a hydraulic fracturing job, to analyze its impact independently.
In order to understand the impact of hydraulic fracturing chemicals on short term (6 month BOE), midterm (12 month BOE) and long term (24 months BOE) productivity, an analysis is performed using feature selection methods like SelectKBest (F Regression score), Tree-based regression, Mutual Info Regression, Recursive Feature Elimination (RFE) and Correlation-based Feature Selection (CFS). In this paper, Max Ingredient Mass (LBS) is utilized for correlation with production to determine if more or fewer quantities should be used in the Powder River Basin. Comprehensive data exploration is carried out to generate correlations between the chemicals and productivity which helps to identify and link multiple causes to effects and weigh the strength of the correlations, which might not be obvious to the naked eye. A comparison of algorithms for three different target variables shows how certain chemicals are significant at the beginning of production and gain/lose their importance with time.
The present paper provides in-depth insight into the impact of the most commonly used chemical types in shale completions. It uses machine learning to provide a truly novel understanding of the individual contribution of these products. It adds to the understanding around this concept by developing a cause and effect relationship between chemical design and composition and the impact on production and provides recommendations on process optimization in completion design.
Fracture Hit Mitigation Through Surfactant-Based Treatment Fluids in Parent Wells
Authors: Xu Liang , Ogle James , Collier Todd 
Published: August 2019

Abstract
Pre-loading parent wells with surfactant-based treatment fluids for frac hit mitigation has been applied extensively in liquids-rich shale plays, where infill drilling and tighter well spacing are prerequisites for improved production and economic return. Pre-loads can provide a significant and temporary increase in fracture network pressure if done properly and are most effective with a surfactant and solvent package. However, it remains elusive why specific chemical packages help improve the parent well production, although the notion of capillary force resistance reduction for further treatment fluid leakoff into fractures and rock wettability alteration by surfactant has been proposed previously. Recent residual surfactant analysis in produced water from both parent and child wells indicates that there is indeed hydraulic communication after frac hits, and field trials in the Wolfcamp suggest that adding the same surfactant package in primary frac fluids in child wells can migrate to parent wells, thereby potentially activating various secondary oil recovery mechanisms.
Astrategy for properly selecting a surfactant solvent package is presented for parent wells. Most conventional surfactant tests do not provide much insight in the absence of formation rock. Instead, a rock-on-a-chip microfluidic device is used to illustrate the interactions between parent and child wells when frac hits occur. Spontaneous imbibitions of primary frac and secondary treatment fluids into formation rocks are performed along with computed tomography (CT) imaging to understand the surfactant efficacy for enhancing leakoff into secondary fractures.
Oil recovery and associated water saturation in the microfluidic-based device with or without surfactant are quantified and reveal that the oil recovery is enhanced with surfactant, and water saturation in the parent well could be reduced thereby mitigating water blocks from primary frac fluid invasion from child wells. Spontaneous imbibition results provide insight into a surfactant's effectiveness to leakoff into secondary fractures within a matter of several days, which coincides with a typical short time window for the offset frac to begin to achieve maximum pressure support.
Application of Multivariate Statistical Methods to Reservoir Fluid Characterization in Unconventional Liquid-Rich Basins
Authors: Afekare Dayo Akintan 
Published: August 2019

Abstract
The objective of this work is to demonstrate the application of multivariate statistical tools in unconventional reservoir fluid characterization using publicly available PVT data and design a fluid characterization workflow. Several oil and gas properties were predicted for fluids in Eagle Ford groups, namely Eagle ford 1 (ef1), Eagle Ford 2 (ef2), Eagle Ford Shale (efs) and Eagle Ford (ef).
Principal component analyses (PCA) was first used for dimensionality reduction and selection of components that account for large variation of the dataset. Next, multivariate regression analyses were used to predict PVT properties as a function of reservoir fluid composition using gathered reports. Major steps in regression are trends observation, correlation of trend parameters with composition, model reconstruction and calibration.
PCA results show that virtually all original variables are required to account for substantial variation within the PVT datasets. It is also noticed that the first 3 principal components account for 84% of dataset variability. Regression models of different fluid properties including gas-oil ratio (GOR), oil formation volume factor, gas density, gas viscosity, API, saturation pressure developed for Eagle Ford Shale formation fluids demonstrate a superior level of accuracy on average (R sq. = 0.8-0.94) and it was revealed that most properties can be determined directly from mole percentage of hydrocarbon fractions. A strong correlation between initial reservoir pressure and formation true vertical depth (TVD) was identified from the PVT data. Consequently, oil formation volume factor and GOR maps covering areas where analysed data were collected from with R sq. above 0.8 were designed. A user-friendly reservoir fluid characterization workflow was proposed and can be applied to any type of reservoir fluid window- black oil, dry gas or condensate - in a liquid-rich basin. Exceptions were identified and discussed.
Reliable estimation of reservoir fluid properties has a tremendous impact on different facets of unconventional reservoir field development: drilling, completion, reservoir management, and economic analyses. Current understanding of shale PVT is inadequate due to difficulty in obtaining representative fluid samples before (low permeability) and after (large produced water volumes) hydraulic fracturing. Thus, this study builds on recent efforts in understanding shale PVT behavior and potentially eliminating need for rigorous fluid sampling using multivariate statistical methods.
Gas-Cycling Enhanced Oil Recovery in Liquids-Rich Production
Authors: Thomas F. Brent , Piwowar Michael , Zhang Hongmei , Gibb William 
Published: August 2019

Abstract
Gas cycling enhanced oil recovery (GCEOR) is under intense investigation. A novel experimental procedure was developed to quantify the parameters that affect GCEOR performance. Porous media, exhibiting in-situ liquid permeability from 200 nD to 2 µD, were evaluated for GCEOR upside. The influence of cycling pressure, injection gas composition, soak time and level of primary depletion before initiation of GCEOR were measured.
The innovative experimental design for core-flow testing permitted the quantification of GCEOR using large lab-scale hydrocarbon pore volumes (HCPV). The unique experimental design allowed nano-darcy media to be tested using a time line comparable to conventional millidarcy media. Two dominant flow regimes were incorporated: matrix mass transfer into the fracture and flow within the fracture. Three mechanisms for EOR are described: extraction, swelling, and reduction of interfacial tension. Full reservoir conditions were reproduced and primary depletion followed by huff and puff GCEOR were evaluated, while changing the design parameters listed above. This work was performed on diverse oil and rock properties.
More than 30 primary depletion tests followed by GCEOR have been conducted. The effects of cycling pressure, injection gas composition, soak time, level of primary depletion before GCEOR, and other parameters were investigated. Due to large HCPV, good mass balance was maintained and sufficient fluids were produced, as a function of cycle number (huff and puff), in order to be able to measure effluent gas and liquid compositions and densities from each cycle along with the recovery of original oil in place (OOIP). All testing was done in order to quantify the relative benefit of huff and puff GCEOR compared to primary depletion recovery. Results indicate that recovery of OOIP can be more than doubled by implementing GCEOR: cycling pressure should be optimized (highest pressure does not necessarily perform the best); soak time/ huff time may compensate for non-optimal pressure operation; injection-gas composition can impact performance; gas utilization values are low compared to conventional continuous gas injection projects; less depletion before GCEOR initiation can accelerate recovery and can access residual oil that was not produced at higher levels of primary depletion.
The Impact of Cluster Spacing on Multi-Fractured Well Performance
Authors: Chen Rongqiang , Xue Xu , Datta-Gupta Akhil , Yu Henry , Kalyanaraman Nishkriya 
Published: August 2019

Abstract
A major outstanding challenge in developing unconventional wells is determining the optimal cluster spacing. The spacing between perforation clusters influences hydraulic fracture geometry, drainage volume, production rates, and the estimated ultimate recovery (EUR) of a well. This paper systematically examines the impact of cluster spacing in the Eagle Ford shale wells by calibrating fracture geometry and fracture/reservoir properties using field injection and production data and evaluating the optimal cluster spacing under different reservoir conditions.
We explore a sequential technique to evaluate and optimize cluster spacing using a controlled field test at the Eagle Ford field. This study first identifies the fracture geometry by history matching the field injection treatment pressure. Using the rapid Fast Marching Method based flow simulation and Pareto-based multi-objective history matching, we match the well drainage volume and the cumulative production to calibrate the fracture and SRV properties. The impact of cluster spacing on the EUR are examined using the calibrated models. We run injection and production forecasts for various cluster spacing to investigate optimal completion under different reservoir conditions.
The unique set of injection and production data used for this study includes two horizontal wells completed side by side. The well with tighter cluster spacing has larger drainage volume and better production performance. This is because of the increased fracture complexity in spite of the impact of stress shadow effects leading to shorter fractures. The calibrated models suggest that most of the fractures are planar in the Eagle Ford shale. The well with wider cluster spacing tends to develop longer fractures but the well with tighter cluster spacing has better stimulated reservoir volume with enhanced permeability, thus resulting in better drainage volume and production performance. From the optimization runs under different reservoir conditions, our results seem to indicate that when natural fractures are present or when stress anisotropy is high with no natural fractures, the wells with tighter cluster spacing tend to outperform the wells with wider cluster spacing. However, severe stress shadow effect is observed when stress anisotropy is low with no natural fractures, likely making tighter cluster spacing wells less favorable.
The calibrated fracture geometries and properties with a unique set of Eagle Ford field data explain the performance variation for completions using different cluster spacing within the reservoir and provides insight into optimal cluster spacing under different reservoir conditions (low vs high stress anisotropy and with/without natural fractures).