bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Evaluation of Solvents for Improved Oil Recovery in Shale Oil Reservoirs
Authors: Ozowe Williams , Quintanilla Zach , Russell Rod , Sharma Mukul 
Published: October 2020

Abstract
Despite recent technological advances in horizontal drilling and hydraulic fracturing, primary production from unconventional oil reservoirs is usually less than 10 percent of the original oil in place. This low recovery has made it essential for operators to test methods that aim to improve recovery efficiency and recover incremental oil from existing wells. One of such methods is the use of solvents for improved recovery in shale oil reservoirs via cyclic gas injection also referred to as a "huff-n-puff" process. Previous laboratory studies have demonstrated promising results on unpreserved shale core plugs using CO2, N2 and C1 as solvents, however, none have shown recovery results using ethane or higher molecular weight gases for cyclic gas injection.
This paper presents improved oil recovery results from cyclic gas injection experiments using C2 and n-C5 in comparison to N2 on unpreserved Eagle Ford crushed samples and core plugs with n-C12 as the oil phase. Core plugs and crushed preserved shale samples were vacuum dried and then re-saturated with n-C12 at 6000 psi for 48 hours, then huff-n-puff experiments were conducted using n-C5, C2 and N2. Recovery factors obtained using n-C5 at injection pressures of 2000 psi and 5000 psi showed that oil recovery increased with an increase in surface area to volume ratio. For the same surface area to volume ratio, oil recovery is higher at higher injection pressures. A comparison of recovery factors between C2 and n-C5 show that C2 was more effective than n-C5 because it showed higher recovery factors at 2000 psi and 5000 psi injection pressure. NMR T2 distributions also showed that C2 was able to recover more oil from the small and intermediate pore sizes without leaving behind any residual fluid in the small pores unlike n-C5. The higher recovery factors obtained for C2 are a result of its lower viscosity and because it is able to expel more oil out of the shale pore space as it flashes to gas upon depressurization compared to n-C5. Comparing N2 recovery results to both C2 and n-C5 at 5000 psi injection pressure demonstrated that N2 yielded the lowest recovery factors because it is essentially immiscible with the oil. These experimental results can be used as the basis for scaling up to field scale huff-n-puff gas injection pilots.
Leveraging Integrated Production Modeling and Digital Platforms to Maximize Liquid Yield and Reduce OPEX from Liquid-Rich Marcellus Reservoirs – A Field Study
Authors: Kumar Hemant , Bhinde Tej , Dias Edgar , Billiter Travis 
Published: October 2020

Abstract
This work describes the use of integrated production modeling (IPM), along with digital platforms, as reliable tools to increase liquid yield, reduce operational expenditures ($/BOE) and maximize the project's net present value (NPV) in the Appalachian Basin. The results of the work, as applied to a real field show that the liquid yield for the gas condensate produced fluids can be increased by 3-5%; compression energy and process heating requirements can be reduced significantly.
The condensate to gas ratio (CGR) in Marshall County, West Virginia (WV) changes rapidly from southeast to northwest. For example, on a single pad (8-10 wells) the CGR of the northwestern wells is ~40% higher than the CGR of southeastern wells. Moreover, the CGR decreases with production time. A fixed-pressure, two-stage separation process is suboptimal for this area. Calibrated physics-based models leveraged to an integration platform can significantly improve the facilities performance.
The facilities set up is as follows: the gas produced from a well is fed to a line heater followed by a surface choke. The fluid then enters a gas processing unit (GPU) separator. The separated fluids from each well's GPU in the well pad are processed at common facilities consisting of separation and compression. The processed gas is exported to a sales gas line and the liquids are transported separately.
A fully integrated model has been built for eight wells on a pad. The reservoir and well models were history matched and then integrated with the surface network and facilities (compressor, heater) using network modeling and integration platforms. Various scenarios were run to identify the optimal pressure setting for a given month. The optimization exercise yielded 5-10% additional natural gas Liquids (NGLs) on a pad by increasing the GPU pressures by 100-200 psi. The higher GPU pressures reduced the well choke pressure drop, thereby reducing the heating requirements by 50% as the Joule-Thomson cooling across the choke was minimized. The reduced cooling also minimized flow assurance risks due to hydrate formation and reduced inhibitor injection costs. Finally, the compression energy requirement was reduced via better management of the pressure staging.
The developed integrated models, combined with digital platforms, offer novel and versatile capabilities for efficiently operating an asset to maximize liquids and reduce operational expenditure (OPEX). The deployment of a physical model-based digital oil field will facilitate the validation of these models on a continuous basis. This in turn will allow changes to be made in the field to keep the system optimized as the characteristics of the producing fluids change with time.
Surfactant-Aided Low-Salinity Waterflooding for Low Temperature Carbonates
Authors: Shi Yue , Miller Chammi , Mohanty Kishore 
Published: October 2020

Abstract
Carbonate reservoirs tend to be oil-wet/mixed-wet and heterogeneous due to mineralogy and diagenesis. Some carbonate reservoirs are fractured especially dolomite formations. The objective of this study is to improve oil recovery in low-temperature dolomite reservoirs using low salinity and surfactant aided spontaneous imbibition. The low salinity brine composition was optimized using zeta potential, contact angle experiments, and wettability index calculations. Significant surface reactions on dolomite rocks were observed at the salinity of 2500 ppm. Thirty-seven surfactants were evaluated for wettability alterations using contact angles. Surfactants with lower IFT and lower contact angles were selected for spontaneous imbibition. In spontaneous imbibition experiments, some formulations produced a significant amount of oil compared to the control samples without any surfactants. Two cationic surfactants produced 41-53% of OOIP and an AOS anionic surfactant produced 39% of OOIP in a month. These experiments demonstrated that a combination of low water salinity and surfactants can make the originally oil-wet dolomite rocks more water-wet and improve oil recovery by imbibition at a low temperature of 35 °C.
Rise of Machines: Time to Change the Petroleum Engineering Curriculum
Authors: Samuel Robello 
Published: October 2020

Abstract
The model of "learn at school" and "do at work" is outdated and must keep up with the changing environment of the Industrial Revolution 4.0 (IR 4.0). The petroleum engineering curricula, therefore, must also change accordingly and this change is needed at a time the new generation of students entering the workforce is different from the generation leaving the workforce. It is time to examine the core curricula being taught at petroleum schools so that long-term sustainability can be established. The petroleum education has been modified very little in the past 30 years and needs to change in the post-Google era to cater to the tech-savvy minds of the modern student. Although developments in technology have positively responded to the needs of the industry in the past, its future advancement will include areas such as telemetry, sensors and data handling, and analytics. Thus, a new approach to engineering education, involving the fundamentals of engineering sciences that culminates in the development of experiential learning on cyber-physical systems, is important. The paper presents and lays out the urgent need for a new type of curriculum for petroleum engineering education that encompasses engineering, science, and technology.
Network Optimization Models at Greater Kuparuk Area Using Neural Networks and Genetic Algorithms
Authors: Murray Rodney L. , Hopkins Reese S. , Valentine Douglas K. 
Published: October 2020

Abstract
The Greater Kuparuk Area, located on the North Slope of Alaska, began production in 1981 and has produced over 2.5 billion barrels to date. The area contains six oil fields flowing into three central processing facilities with 47 drillsites and over 1,200 production and injection wells. The facilities are primarily gas constrained due to limits from the gas lift compressors, and secondarily water constrained due to injection pump capacity. An optimization program using the equal slope concept is currently in use for lift gas allocation. A previous attempt to more rigorously optimize the production system using commercial software resulted in better lift gas allocation, but computation time lead to the cessation of its use for daily optimization.
The objective of this work was to develop a fast, flexible optimization model that recommends well status, lift gas rates, and water injection rates. The model uses field data and data generated by the previous surface models to develop the hydraulic models as well as current facility conditions and constraints. The model contains four components. The first was a function that estimates producer and injector performance. The second is a function that gathers and interpolates well performance models with physics-based models. Third, the drillsite header pressures were estimated using a neural network. Finally, a genetic algorithm is used to search for the optimal well status, lift gas rate, and water injection rate for each well. Connections were made to databases to run the model using field conditions at any time over the last five years.
The hydraulic model for three phase flow utilizes a neural network, whereas a simpler linear based model is used for the water injection system. The hydraulic model was rigorously back tested using field data over a two-year period with weekly model retraining. Drillsite header pressures deviated 6 psi on average from actuals, which is on par with commercial software. The optimization converges in under 90 seconds in a single facility optimization run. The recommendations from the optimization program are expected to increase oil rate 1.5% in the existing system.
While production optimization using genetic algorithms and neural networks has been presented for over 20 years, there are not many, if any, known industry applications of optimizing the production and injection networks simultaneously using neural network models. The program was written in Python and deployed on cloud computing. The tool is used to calculate daily net oil benefit per well, prioritize shut-in wells when the facility is constrained, and optimize injection pumps and drillsite configurations. Additionally, the model is designed to accept new engineer-specified source wells to understand the impact of backout when developing new projects. Overall, the model has provided a platform for engineers to make optimization decisions in a complex, interdependent system.
Exploiting the Full Potential in Automated Drilling Control by Increased Data Exchange and Multi Disciplinary Collaboration
Authors: Gjerstad Kristian , Bergerud Ronny , Thorsen Stig Tore 
Published: October 2020

Abstract
The drive for cost efficient solutions in drilling has become stronger the last few years, and one of the approaches to this end is to increase the level of automation. Automation is multi-disciplinary task, and to really succeed, there is a need for collaboration between the different parties in the drilling industry. In this paper we discuss which underlaying technologies within instrumentation, control systems and communication technology that should be in place for a typical model-based automation and well protection software to work optimal. We elaborate on what is needed to take out the full potential of performance-enhancing functionalities in automated drilling control software. We highlight the gaps present today and how this affects the automation efforts as a whole. The discussion shows that there are some low-hanging fruits that can give significant cost reduction and improvements in automation and safety, while there are also some technology gaps that will take some time to fill and that require coordinated efforts between the vendors.
Significance of Incorporating Water-Wet Regions for Modeling Low Salinity Waterflood in Oil-Wet Carbonates
Authors: Sharma Himanshu , Mohanty Kishore 
Published: October 2020

Abstract
Recent studies have shown that low salinity waterflood can recover additional oil from oil-wet carbonate reservoirs by altering their wettability. Further studies have investigated key mechanisms for wettability alteration, such as, interaction of sulfate ions with organic acids, importance of divalent cations, role of oil acid/base content. The progress, however, has been limited in terms of modeling the wettability alteration process. A few recent studies have reported mechanistic models based on surface-complexation reactions. However, these models have their limitations when applied to oil-wet reservoirs because the injected brine is assumed to interact with the entire rock surface. In reality, the surface reactions occurs in the water-wet regions and the water-wet regions increase as a result of wettability alteration. In this study, a multiphase multicomponent finite-difference reservoir simulator was developed, incorporating the change in oil-wet/water-wet rock fractions, for modeling low salinity waterflood in carbonates. The wettability alteration process was modeled by incorporating key surface-complexation reactions. Single-phase and oil recovery coreflood simulations were performed in which modified brines, such as seawater and diluted seawater, were injected. The simulation results show that the extent of reactions of low salinity brines is much less when these reactions are assumed to take place only in the water-wet regions of oil-wet rocks. Single-phase simulation results agreed well with sulfate delay and dolomitization reactions observed experimentally. Oil recovery simulation results showed reasonable agreement with coreflood results of low salinity water injection reported in the literature. In these simulations, the water-wet rock fraction evolved as a result of wettability alteration on injecting diluted seawater. Simulating geochemical reactions only on the water-wet regions is critical for modeling low salinity waterfloods. In this study, we developed an improved model with this feature and found it to be effective for modeling low salinity waterfloods.
Enhancing Oil Recovery Using Aqueous Dispersions of Silicon Dioxide Nanoparticles: The Search for Nanoscale Wettability Alteration Mechanism
Authors: Afekare Dayo 
Published: October 2020

Abstract
Enhancing oil recovery using silica-based particles appears to be a promising technique. Yet, this method remains novel partly because it suffers from inadequate scientific understanding. In this study, a nanoscale investigation of silicon dioxide nanoparticles for EOR in tight oil rocks is performed using high-resolution force spectroscopy with a case study of Tuscaloosa Marine Shale (TMS).
The dominant rock minerals in TMS were used as substrates and COOH-, C6H5-, and CH3- terminated probes were used to represent crude oil functional groups for atomic force microscope (AFM) experiments. Next, different concentrations of hydrophilic SiO2 nanoparticles dispersed in 1 wt% NaCl were prepared and used as nanofluids. Geologic substrates were immersed in fluid cells and AFM was used to characterize chemical probe/substrate adhesion forces and energies in respective solutions.
Atomic force microscope results showed that aqeous dispersions of silicon dioxide nanoparticles promote wettability towards a less oil-wet state at the nanoscale by overcoming the adhesion force and energy barrier to disrupt the oil-rock interface and create new nanofluid-rock and oil-rock interfaces. This is applicable to tight oil reservoirs containing predominantly organic and inorganic pores and polar and non-polar crude oil fractions such as TMS. Percentage changes in adhesion energy derived from AFM were in excellent agreement with existing classical theories. Through surface characterization, the irreversible adsorption of nanoparticles which is central to sustainable wetting effects was observed. Adhesion force and energy are resolved in multiple intermolecular interactions such as electrostatic – or electric double layer – repulsion, non-electrostatic interaction and structural interactions. This study throws new light on fundamental mechanisms of nanofluid EOR at the nanometer scale.
Graphene as a Surfactant Carrier: A Performance Study for Enhanced Oil Recovery Applications
Authors: Bardhan Anirudh 
Published: October 2020

Abstract
Graphene as surfactant carrier material for EOR/IOR is used. Its performance is evaluated through adsorption, desorption, interfacial tension and emulsification studies. Moreover, the kinetic and thermodynamic parameters are identified in order to understand the physicochemical behavior pertaining to its applicability in surfactant flooding. The surfactant carrier, graphene is acquired and its physicochemical behavior is characterized by X-Ray diffraction, Fourier transform infrared spectroscopy, surface area analysis, etc. The uptake capacity of the surfactant is investigated by adsorption and desorption studies at different subsurface conditions. The kinetics of the process are identified to understand the rate and order of the reaction, whereas thermodynamic behavior of the surfactant carrier is evaluated to find its Gibbs free energy, enthalpy, entropy, activation energy, etc. Further, a reduction in interfacial tension and stability of emulsion between crude oil and brine is inspected. The uptake capacity of the surfactant obtained from the adsorption and desorption study confirmed that adequate quantities of surfactant can be transported into the deep subsurface with minimal loss. This infers the requirement of surfactant in lesser quantity when compared to surfactants without any nanocarrier. Similarly, a reduction in interfacial tension and increase in emulsion stability is expected to be increased. Furthermore, graphene shows a remarkable change in hydrophobicity with a change in pH and salinity which indicates that the properties can be suitably tailored as per requirement, making it a good candidate for surfactant EOR/IOR. Also, the obtained thermodynamic data suggest endothermic and spontaneous adsorption behavior, which may be a favorable phenomenon when subjected to the higher subsurface temperature. Graphene as a surfactant carrier and its performance is investigated for the first time rendering it unique for EOR/IOR applicability studies.
Formation Integrity and Pore System Evaluation for Stimulated Sandstone Formation Using In-Situ Generated Acid Catalyzed by A Fused Chemical Reaction
Authors: Gomaa Ibrahim 
Published: October 2020

Abstract
This study aims at evaluating the mechanical integrity and the changes in the pore system of illitic sandstone formations being treated with HF acid generated in-situ and thermochemical fluids (TCF). Firstly, the acid-generating fluids were injected separately inside the core within a typical core flooding experiment. After that the core permeability, NMR porosity and rock static and dynamic parameters such as rock strength (UCS), dynamic Young's modulus, Poisson's ratio, shear modulus and bulk compressibility were evaluated before and after the treatment. Sand production prediction model was used to examine the potential of sand production problems for the cores treated with the in-situ generated acid (ISGA) and the TCF.
Treating Scioto cores with the ISGA only led to permeability enhancement with final to initial permeability ratio KfinalKinitial of 1.2. In addition, treating the same cores with acid generating fluids and thermochemicals resulted in higher permeability enhancement with KfinalKinitial of 485. This higher enhancement in the formation permeability was attributed to the creation of some microfractures as was proved using the NMR scans. There was a reduction of the cores' static and dynamic parameters after being treated with the ISGA. This reduction was even higher after treating the core with thermochemical fluids. However, the sand production prediction model stated that the reduction in rock mechanical parameters would not lead to sand production problems.
Analytical Solutions for Predicting Fracture Outlet Temperature of Produced Fluid from Enhanced Geothermal Systems with Different Well-Completion Configurations
Authors: Onay Mehmet Emin 
Published: October 2020

Abstract
Enhanced Geothermal Systems (EGS) are those in which advanced drilling and fracturing technologies are required to extract heat energy from the earth's crust in areas where higher heat flow than average and natural permeability and/or fluid content are lacking. In order to make an EGS project successful, extensive studies should be conducted, especially for the purposes of evaluating and predicting future thermal performance of subsurface system. The main objective of this study is to present novel analytical models and their analytical solutions for predicting the temperature and heat recovery behaviors of four different hydraulically fractured well configurations of EGS created in a hot dry rock formation. The configurations considered are a single-vertical-planar fracture intersecting a horizontal-well doublet system orienting in a horizontal plane, multi-vertical-planar fractures intersecting a horizontal-well doublet system orienting in horizontal plane, a single-vertical-planar fracture intersecting a horizontal-well doublet system orienting in a vertical plane, and multi-vertical planar fractures intersecting a horizontal-well doublet system orienting in a vertical plane. In developing these analytical solutions, basic concepts of conservation of heat due to convection and conduction have been applied. The partial differential equations describing and coupling convective heat transfer in hydraulically fractured wells with conductive heat transfer in the matrix system, which is assumed to be homogenous, for each well completion type were solved subject to the appropriate initial, interface and outer boundary conditions by using the method of Laplace transformation and inverted numerically by using the Stehfest inversion algorithm (Stehfest, 1970). The solutions presented in this study treat hydraulic fractures as porous media. The analytical solutions derived were validated by using the existing solutions available in the literature for the single-fracture and multiple-fractures intersecting a horizontal-well doublet system, given by Arpaci et al. (1966) and Gringarten et al. (1975) who both treat hydraulic fractures 100% porous, respectively. The solutions developed for each of the well completion type were used to perform parametric studies to investigate the effect of parameters on temperature of produced fluid and in return on feasibility of a given EGS completion. Main conclusions obtained from the extensive parametric studies are: Geothermal gradient has substantial effect on fracture outlet temperature of the produced fluid in EGS models having vertical flow in fractures especially for low injection volumetric flow rates, hydraulic fracture porosity has substantial effect on determining intrinsic velocity of fluid within pores of fracture, and in EGS models having vertical flow, downward flow case is observed to have better performance in terms of heat recovery factor than upward flow case of the same model.