bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Novel Granular Profile Control Agent for Steam Flooding: Synthesis and Evaluation
Authors: Wang Hongsheng , Rabiei Minou , Lei Guanglun , Wang Sai 
Published: April 2017

Abstract
To block big pore throats and channels, caused by high-temperature steam, in vicinity of injection wells of steam flooding, profile control agent should be inject. For the optimum effect, its properties should include excellent heat resistance and some permeability after consolidation, which is beneficial for improvement of sweep coefficient.
In this paper, we do a study on how to synthesize a novel granular profile control agent and evaluate its properties. The basic procedure includes synthesis material selection, synthesis method optimization, consolidation properties test (setting time, consolidation strength and heat resistance) by orthogonal experiments and simulation experiments by heterogeneous parallel dual-core flooding tests.
Results show that profile control agent is self-cemented, inorganic particle with the scale of mm, matching the scale of big pore throats and channels in vicinity of injection well. Initial setting time greater than 7h, consolidation strength up to 3.5MPa and excellent heat resistance can ensure its feasibility and completeness in high-temperature steam. Profile control agent with proper size can form core with some permeability and porosity. The core formed has stable and flushing-resisting flowing channels. The relationship between permeability of core formed and diameter of particles is established, which means with known permeability ratio of formation, specific diameter and injection PV can be chosen to satisfy the homogeneity.
A Comprehensive Multi-Platform Petroleum Engineering Toolbox for Oil and Gas Industry
Authors: Balaji Karthik , Suhag Anuj , Ranjith Rahul , Tuna Tayfun , Temizel Cenk , Aminzadeh Fred 
Published: April 2017

Abstract
There are certain online tools that serve as a comprehensive toolbox in specific areas of engineering, including but not limited to, chemical and mechanical engineering. These tools provide quick online access to a broad range of equations used in the area of interest while serving as a convenient tool for professionals who do not have access to a comprehensive library or those who are not familiar enough with the subject to locate the equation required. Thus, the objective of the online Petroleum Engineering Toolbox is to provide users in the academia and industry – with or without a petroleum engineering background – a comprehensive and convenient round the clock accessible source of petroleum engineering and related calculations, offering calculations and technical description of over 1000 formulas.
Petroleum Engineering Toolbox consists of 2 main sections; equations and a technical manual/reference, featuring a total of over a thousand calculations in reservoir, drilling, production, well testing, fluid flow, laboratory experiments, economics, PVT, logging, optimization, well stimulation, EOR and thermodynamics. The purpose of technical manual/reference section is to serve as a library for reference tables, charts, tables in petroleum engineering, thus, providing a very convenient tool for engineers working anywhere in the world, especially in places where it is difficult to access sources of information including fields, offshore and onshore remote locations. The manual outlines the theory of equations used in calculations with units for the most convenient and user-friendly experience.
The petroleum engineering toolbox is available online and as a mobile application for better use on mobile devices. The online interface of Petroleum Engineering Toolbox is entirely built on top of open source technology. Server side connection is done by Apache 2.4.9 Web Server and PHP Version 5.2.4. Formula representations are done by MathJax open source library. Petroleum Engineering Toolbox is available for PC, Mac, tablet, or any mobiles device through mobile friendly online user interface. It is also accessible for iPhone and iPad user as a mobile application.
Currently, even though there are tools for specific calculations, there is no such comprehensive and globally-available toolbox in all platforms in the oil and gas industry, thus, Petroleum Engineering Toolbox is a first of its kind serving the professionals in the oil industry and the academia with its expanding content.
Improving Rollover Crashworthiness of Heavy Trucks Equipped with Towers and Booms Overhanging the Cab
Authors: Friedman K , Hutchinson J , Bui K , Mattos G. , Bozzini S 
Published: April 2017

Abstract
Many purchasers and operators of heavy trucks may be unaware of the potential added danger to occupants from equipment overhanging the cab under rollover conditions. This study examines US and EU regulations for heavy truck occupant protection and the options for minimizing injuries with aftermarket equipment. US and EU government regulations regarding occupant protection in heavy trucks were reviewed and their shortcomings with regard to vehicles modified with a boom structure are highlighted. A finite element model of a truck and boom were created. Baseline performance was verified against real world data and simulations run for rollover impacts. Significant intrusion into the occupant compartment due to the loading of the overhead boom was observed. Overhead booms can deform during contact with the ground, with longer overhanging associated with greater intrusion into the cab under rollover impact conditions. The effect of these structures on heavy truck crashworthiness, especially with regard to low strength OEM cabs, must be considered during up-fitting. A simulation was run with an aftermarket device and conclusions are presented.
A Neural Network Approach for Modeling Water Distribution System
Authors: Popa Andrei S. , O'Toole Conor , Munoz Juan , Cassidy Steve , Tubbs Dallas , Ershaghi Iraj 
Published: April 2017

Abstract
The successful waterflooding field development depends not only of the understanding of reservoir characterization, sub-surface injection displacement and sweep-efficiency, but also an accurate and effective design and operation of the surface network’s water injection distribution. In certain cases, the latter is critical for the successful waterflood operations in large fields with thousands of wells and high volume of new development activity.
For the purpose of this study, we are presenting a new data-driven approach to accurately estimate the injection rate in all non-instrumented wells in a large waterflooding operation. A collection of data driven tools, including statistics, clustering, simulation and an artificial neural network model were employed to prime and model the data. As a final point, the neural network leverages instrumented wells’ data and serves as an accurate real-time proxy to estimate missing injection rate measurements in non-instrumented wells. The system’s accuracy was validated by comparing the estimated rates for different wells on a different branch with the ones measured at physical wells. The neural network model trained on the cleansed data set revealed a high performance system with a &gt;0.93 R2 values for both training and validation sets.
The paper outlines both the methodology and procedures used to analyze a branch of the water network system, and the modeling of accurate estimation of injection rates. The model performance is remarkable having used only field and wellhead measured data and considering the natural uncertainty inherited in these values. Finally, this system provides the capability to estimate the flow rate for every non-instrumented well in the field and respond to exceptions in relevant time.
Developing a Smart Proxy for the SACROC Water-Flooding Numerical Reservoir Simulation Model
Authors: Alenezi Faisal , Mohaghegh Shahab 
Published: April 2017

Abstract
The preferred common tool to estimate the performance of oil and gas fields under different production scenarios is numerical reservoir simulation. A comprehensive numerical reservoir model has tens of millions of grid blocks. The massive potential of the existing numerical reservoir simulation models go unrealized because they are computationally expensive and time-consuming [1]. Therefore, an effective alternative tool is required for fast and reliable decision making. To reduce the required computational time, proxy models are developed. Traditional proxy models are either statistical or reduced order models (ROM). They are developed to substitute the complex numerical simulation by producing a representation of the system at a lower computational cost. However, there are shortcomings associated with these approaches when applied to complex systems.
In this study, a novel proxy model approach is presented. The smart proxy model presented in this article is based on artificial intelligence and data-mining techniques. A numerical simulation run is designed for the smart proxy objectives. The static and dynamic data from the simulation run are extracted. Selected data parameters are used to create a spatial-temporal database for the smart proxy model. The smart proxy is trained, calibrated, and validated using a series of neural networks for the targeted reservoir property. To validate the smart proxy model, it is deployed to replicate a blind numerical simulation run. The developed smart proxy model can replicate the simulation outcomes in a very short time (seconds) with an acceptable range of error.
A Novel Adaptive Non-Linear Regression Method to Predict Shale Oil Well Performance Based on Well Completions and Fracturing Data
Authors: Bakshi Amol , Uniacke Eric , Korjani Mehdi , Ershaghi Iraj 
Published: April 2017

Abstract
This paper presents the results of applying a novel nonlinear regression method, Variable Structure Regression (VSR), to forecasting well performance given the well completion and rock composition data. We compiled and analyzed data from 79 producing wells from the same unconventional reservoir. Calibration using the performance data of 60 wells was used to predict the behavior for the rest, and the predictions are quite successful.
Input parameters for the regression model were the number of frac stages, the average length of each stage, isochore, total organic content, proppant-to-fluid ratio and a rock brittleness metric derived from illite content. The cumulative oil production after three months and after 18 months was considered as outputs of the prediction model. Scatterplot analysis did not indicate any obvious correlations between the individual input parameters and the output, thereby necessitating the use of a more complex multi-parameter model.
Given the relatively small training data size and the complexity of the problem, the VSR method achieved satisfactory prediction accuracy. For predicting 3-month cum oil, model calibration using the performance data of 60 wells was used to predict the behavior for the remaining 19. About 70% of the predictions were within a 30% margin of error. For predicting 18-month cum oil, data from 33 wells was used to predict the production of 10 wells. About 80% of the predictions for the 18-month cum production were within the 30% error margin.
Flow Control Devices in SAGD Completion Design: Enhanced Heavy Oil/Bitumen Recovery Through Improved Thermal Efficiencies
Authors: Banerjee Sudiptya , Hascakir Berna 
Published: April 2017

Abstract
One method of thermal recovery, steam-assisted gravity drainage (SAGD), has proven a commercial success in heavy oil/bitumen production. However, geological and reservoir heterogeneity often complicate this task resulting in uneven production rates, higher operational costs, and stranded heavy oil/bitumen. This work theorizes that SAGD recovery is improved using flow control devices (FCDs) to force conformance in SAGD laterals. To test this theory, a novel protocol and test flow loop was developed to measure pressure drop across an autonomous hybrid FCD while flowing multiphase mixtures containing steam. This laboratory data was used to qualify existing pressure drop correlations and determine if nitrogen gas, a common test gas to describe FCD pressure drop response, creates suitable data for modeling steam systems. Finally, the flow loop was used to induce a steam "flash", a transition of water at saturation temperature to vapor due to a suddenly decreased pressure environment, within the FCD to determine if steam flashing changes expected pressure drops. Using linear regression, a correlation of expected pressure drop across the autonomous hybrid FCD for mixtures of heavy oil/bitumen, water, and steam was generated. Existing correlations proved inadequate for mixtures containing steam, consistently underestimating pressure drop across the FCD. However, the empirical correlation of this research highly matched laboratory data with an R-squared value of 0.94. A secondary linear model captured modifications in FCD behavior due to steam flashing. This second model also exhibited a strong goodness-of-fit with an R-squared value of 0.96. For both empirical correlations, p-values less than 0.05 were easily obtained, inferring the statistical significance of each correlation. Correlations generated in this research were added to the REVEAL™ reservoir simulation package to accurately forecast FCD impact on SAGD well pair performance. Simulating four year periods of production for SAGD well pairs in Albertan reservoirs consistently show that FCD usage simultaneous improved bitumen recovery by 50% or more and decreased cumulative steam/oil ratios (cSOR) by 12 m3/m3, largely through improved steam chamber conformance and by eliminating steam breakthrough events in the producer. Net Present Value (NPV) analysis of improvements with the additional cost of FCD completion tools unfailingly showed a strong economic argument for the use of FCDs to improve thermal efficiency.
A New Method for Geomechanical Modeling of Subsidence Induced Deformation in Fractured Rocks Subjected to Hydraulic Fracturing
Authors: Qi Qianru , Jha Birendra 
Published: April 2017

Abstract
The inspiration for this study is to improve modeling and representation of diatomites, which constitute a major resource base in California. These rocks, because of their high porosity, experience subsidence, which induces changes in conductivities of the natural fractures. Use of hydraulic fracturing to compensate for low formation permeability has been commonplace yet poorly understood. Here, we examine the coupling of stress and flow during fracture propagation in highly deformable rock containing pre-existing fractures. We consider the interaction between the newly created fractures and pre-existing fractures. This requires modeling the loss in natural fracture conductivity caused by stresses associated with fracturing as well as variations in the overburden stress. We find that opening of a hydraulic fracture leads to changes in the normal and shear stresses on the surrounding pre-existing fractures, which further change their aperture leading to changes in their conductivity. The model improves the prediction of the net permeability enhancement under the new stress field created after hydraulic fracturing. Our results can be used to design smart hydraulic fracturing workflows that can simulate stress-induced subsidence in a more effective manner. Our results also provide a more accurate estimate of permeability enhancement due to hydraulic fracturing.
Comparison of Steam and Polymer Injection for the Recovery of Heavy Oil
Authors: Delamaide Eric 
Published: April 2017

Abstract
Steam injection (including cyclic steam and SAGD) has long been recognized as the favored recovery method for heavy oil, with applications in many fields around the world in particular in California and Canada. More recently, polymer flooding has also become a relatively well accepted method to increase production and recovery in heavy oil fields. Numerous successful pilots have been reported these last few years and field expansions are currently ongoing in Canada, Oman, China and Albania for instance but surprisingly enough, there has been to the best of the author's knowledge no such application in the US.
Both steam and polymer injection have their advantages and their limitations and simple screening criteria have been developed by several authors, however there has never been a detailed comparison of the two methods and this is what this paper proposes to do.
The pros and cons of both steam injection and polymer flood are reviewed in light of fundamentals and field experience: reservoir depth, thickness, oil viscosity, expected recovery, water usage and economics of both processes (in particular capital requirements) are all addressed. Guidelines are then provided for the selection of the right process given the reservoir conditions and the capital constraints.
Results show that while steam injection can achieve much higher recovery than polymer flood and is also applicable in much higher oil viscosity, polymer flooding is not limited by depth or reservoir thickness, has lower operating costs and is also less capital intensive. Thus, there is a large opportunity to develop heavy oil reservoirs using polymer where steam injection is not possible. Delamaide and Euzen (Delamaide & Euzen, 2014) estimated that in the US alone, over 5 billion bbl of oil could be targeted by this technique.
This paper will provide guidance to engineers who need to select the optimum Enhanced Oil Recovery method to apply in given heavy oil fields, going beyond the standard screening criteria. It will also increase awareness on the possibilities of polymer flooding in some reservoirs, with a significant potential target not only in the US but also worldwide.
Case Histories of Solvent Use in Thermal Recovery
Authors: Bayestehparvin Bita , Ali S. M. , Abedi Jalal 
Published: April 2017

Abstract
Steam injection is the most successful oil recovery method for heavy oil and oil sands exploitation. In some cases, solvents are added to steam when steam by itself fails to provide satisfactory recovery factors. In other instances, the use of solvents is justified on the basis of water usage reduction and decreasing greenhouse gas emissions. This has been done in cyclic steam stimulation (CSS), steamflooding, and steam-assisted gravity drainage (SAGD). The range of success in these instances is highly variable. Additional oil/bitumen recovery is claimed in most cases, but the commercial viability is often not discussed.
The use of solvents for the recovery of viscous hydrocarbons is proposed for the obvious reason that mixing a solvent with a viscous oil reduces its viscosity, but the volumes needed are prohibitive; for example, 50% by weight of naphtha would be needed to reduce the viscosity of a one million centipoise bitumen to the level attained by a 200 °C (400 F) temperature increase. When solvents are used with steam, other phenomena are invoked to justify solvent use; for example, solvent condensation at steam temperature to promote the advance of solvent into cold heavy oil/bitumen ahead. In such postulates, the extremely low dispersivity of the solvent in the solid heavy oil/bitumen is of concern. The intent in these processes is to achieve a high mixing coefficient for solvent and heavy oil - just the opposite of what was sought in yesteryear's miscible displacement design. The feasibility of this intent is discussed, via a comparison of heat and solvent dispersion. Another line of thinking is that solvent diminishes the effect of formation heterogeneity.
In this study, several case histories of solvent-addition thermal operations are discussed. A few non- thermal examples are also considered. Detailed results are not always available; the published information is tabulated. The results of the projects are discussed, and interpretations are made where possible. In recent years, solvent is being used in about 10% of the ~1500 SAGD well pairs in operation. In some cases, success is claimed. These are discussed in detail. Use of solvents in CSS is being done in Cold Lake; a new large project (Aspen) is planned there on the basis of solvent stimulation only. Solvents were used to a limited extent in some California steamfloods. None of those showed an improvement as a result of solvent addition. In a couple of cases, solvent injection was done unsuccessfully after a cold heavy oil production with sand (CHOPS) operation.
This is a critical study of solvent use for the recovery of heavy oil/bitumen, showing that in most cases, solvents have not delivered the promise expected. In others, they totally failed. As such, it is hoped that the results will be of value in future planning of solvent injection.
Anaesthetic management of thoraco‐omphalopagus twins with congenital heart disease for separation surgery
Authors: Dogar Samie , Hamid Muhammad , Khan Ausaf , Shamim Faisal , Khan Fauzia 
Published: April 2017

SummaryConjoined twins' separation surgery poses challenges to anaesthetists due to the variable degree of cross circulation, difficulty in positioning, bleeding and limitations of space for sharing between two anaesthetic teams. We present the anaesthetic management for separation surgery of three‐months old conjoined twins. Both babies had congenital heart disease, with one baby hypertensive and commenced on enalpril pre‐operatively. A pre‐operative multi‐disciplinary meeting between all stake holders and a full environment simulation was performed and was helpful. The problems encountered included difficulty in percutaneous central venous line placement requiring surgical cut down and intra‐operative bleeding requiring vasopressor therapy and postoperative intensive care unit stay.
Diseño de un modelo de programación lineal para la planeación de producción en un cultivo de fresa, según factores costo/beneficio y capacidades productivas en un periodo temporal definido
Authors: Sánchez Pineda Daniel Enrique , Ramirez Torres Natalia Lizzeth 
Published: April 2017

El sector hortifrutícola es considerado como una de las vías de ingreso de la población colombiana. Actualmente el departamento de Cundinamarca se destaca como el mayor productor de fresa, con una participación del 63,4% en la producción nacional. La fresa, conocida en el ámbito científico como fragaria vesca, presenta alto consumo gracias a las cualidades de aroma, color y acidez que presenta. La planta de la fresa, se caracteriza por ser perenne, al formar nuevos tallos de forma constante. Un cultivo de fresa, presenta una duración promedio de dos años, seccionados en etapas de funcionamiento. Son escazas las metodologías, que permitan generar una planeación de la producción a nivel frutícola, teniendo en cuenta el comportamiento colombiano. Es por ello que el estudio desarrollado incluye una propuesta de diseño para la planeación de la producción de fresa; teniendo en cuenta factores de costo/beneficio en un cultivo; a partir de programación lineal. Se muestra la formulación matemática y una verificación teórica de su funcionamiento y se evidencia el modelo a nivel teórico es funcional, permitiendo establecer un sistema de verificación de capacidades productivas, de acuerdo a parámetros de entrada específicos.