bluuebunny/crossref_metadata_2025_split huggingface dataset:
Diagenetic Influence of Aqueous CO2 on Fracture Conductivity of Shaly Rocks
Authors: Olabode Abiola , Radonjic Mileva 
Published: October 2014

Abstract
Most sedimentary rock formations (tight or highly porous) have geochemical characteristics that can lead to significant reactive ion exchange processes in aqueous media in the presence of carbondioxide. While geomechanical properties such as rock stiffness, Poisson's ratio and fracture geometry largely govern fluid flow characteristics in deep fractured formations, the effect of mineralization can lead to flow impedance in the presence of favorable geochemical and thermodynamic conditions. Shale caprock which seals more than 60% of oil and gas reservoirs have natural fractures that are unevenly distributed in the geosystem. Experimental works which employed the use of analytical techniques such ICP-OES, XRD, and SEM/EDS techniques in investigating diagenetic and micro-structural property of crushed shale caprock/CO2-brine system concluded that net precipitation reaction processes can affect the distribution of petrophysical nanopores in the seal rock. The results showed that geochemical precipitates can be formed such that fluid flow through open micro and macro fractures may be constrained. Simulation results reported by various researchers suggested that influx-induced mineral dissolution/precipitation reactions within shale caprocks can continuously close micro-fracture networks, while pressure and effective-stress transformation first rapidly expand then progressively constrict them. This experimental research investigates the impact of in-situ geochemical precipitation on conductivity of open micro-fractures under geomechanical stress conditions. Fracture conductivity in core samples of shale caprock with known mineralogical composition from different formations where CO2 injection is on-going are quantitatively evaluated under axial and radial stress using pressure pulse-decay liquid permeametry/core flooding systems. Modeling of the diffusion controlled fluid flow and induced fracture diagenetic alterations in the shale caprocks can be performed using CMG-GEM with artificial core imposing axial and radial geomechanical stress. The possibility of rock-fluid geochemical interactions constricting natural fracture conductivity in long term subsurface CO2 sequestration can lead to significant improvement in shale caprock seal integrity and mitigate injection induced geomechanical perturbation.
Characterization and Selection of Novel Magnetic Tracers for Dynamic Heterogeneity Identification and Quantification
Authors: Ali Khaled , Sohrabi Mehran , Ali Arfan 
Published: October 2014

Abstract
The substantial cost associated with the implementation of any enhanced oil recovery (EOR) program requires a robust understanding of the dynamic heterogeneity of the reservoir. The traditional methods used to determine the preferential flow paths are well-to-well transient pressure tests and tracer tests. This paper provides the results of a series of experiments with new types of magnetic tracers for the prediction of permeability heterogeneities and preferential flow paths in reservoir rock samples. Concentration prfile curves obtained for a number of new magnetic tracers are presented including water-based Ferro Fluids and water-soluble iron oxide powders. The magnetic properties of individual magnetic tracers are also presented which aid in the selection process of the optimum magnetic tracer.
To confirm the validity of the results obtained from magnetic traces, we compare the results against conventional tracer methods on the same core plugs. The results show a very good agreement between the two methods. One of the advantages of the magnetic tracers is the reduced analysis time of the core and effluent samples. The magnetic tracers can also be used in situations where there are constraints with using conventional tracers, for example, due to various chemical reactions in the injection lines, and/or with reservoir minerals deeper in the ground. The results of the new magnetic tracers can help in better understanding of the reservoir heterogeneity and sweep efficiency when combined with existing methods such as pressure transient analysis.
The HPHT Completion Landscape - Yesterday, Today, and Tomorrow
Authors: Lehr Douglas J. , Collins Scott D. 
Published: October 2014

Abstract
High pressure / high temperature (HPHT) wells demand the highest performance equipment and services for the safe and successful completion of these high risk and high cost projects. The demands associated with logging, shoe track isolation, equipment longevity and service life, completion and intervention options, and regulatory compliance push the limits of materials and services. The successful completion of HPHT wells requires advanced materials evaluations, collaboration among many disciplines, and sufficient time for product development and assessment to meet current industry and regulatory standards.
The tools utilized in HPHT completions are usually developed to meet the demands of a well or a family of wells. These tools include, but are not limited to, wellbore isolation plugs, production packers, liner hangers, perforating guns, Casing Collar Locators (CCL tools), formation evaluation tools, seal assemblies, and sub-surface safety valves. The methods used for HPHT tool development are evolving, and the development cycles are lengthening, particularly for ultra HPHT applications in which materials screening and stability assessments are required.
The development of tools for several recent Gulf of Mexico ultra HPHT wells required a multi-year schedule for development to industry and regulatory requirements. Due due to their extreme depths, ultra HPHT wells typically utilize architecture emphasizing small production casings across production intervals. This complicates cementing procedures, and severely limits product options. From an intervention standpoint, workstring options also become limited. Achieving mechanical success in these applications requires the operator to not only manage traditional resources such as time, people, and cash, but also the development of new high performance technologies in an evolving regulatory environment.
What can the industry anticipate for future HPHT wells in terms of architecture, product development, and regulatory challenges? This paper will review the industry's history in these areas, identify current development paradigms and regulatory challenges, and discuss the future challenges in well planning, product development, and regulation.
Visualization of CO2 EOR by Diffusion in Fractured Chalk
Authors: Eide Øyvind , Fernø Martin A. , Graue Arne 
Published: October 2014

Abstract
This work demonstrates that diffusion may be a viable oil recovery mechanism in fractured reservoirs during injection of CO2 for EOR. The oil production rate from diffusion alone, however, depends heavily on the distribution of CO2 within the fracture network and fracture spacing. High oil recovery was observed during miscible, supercritical CO2 injection (RF=95% OOIP after 5 days) in the laboratory using an artificially fractured chalk core plug. The development in 3D fluid saturations from CT-imaging made it possible to study the oil displacement in the vicinity of the fracture, and to calculate an effective diffusion coefficient using analytical methods. A numerical sensitivity analysis, using a validated numerical model that reproduced the experiments, showed that the rate of oil production during CO2 injection declined exponentially with increasing diffusion lengths from the CO2-filled fracture and oil-filled matrix.
Granite Wash Optimization - Validating Completion and Production Techniques
Authors: Crawford E. M. , Energy Linn , Senters C. W. , Bullard K. E. , Leonard R. S. , Woodroof R. A. 
Published: October 2014

Abstract
The Granite Wash continues to be a prolific hydrocarbon producer, with over 1600 wells drilled during the last 10 years. During 2012 and 2013 an extensive development program was initiated by one operator in which 144 wells were drilled and completed with multi-stage hydraulically stimulated horizontal wells. Many of these wells utilized various types of completion diagnostics to: (1) evaluate vertical and horizontal communication within the Granite Wash, (2) identify potential horizontal loading problems and (3) diagnose long-term fracture fluid movement.
This paper reviews more than two years of water-based frac fluid tracer data. It details how the individual tracers were used to quantify communication between various layers of the Granite Wash and between nearby completed offset wells. Also, toe stage frac fluid recoveries were compared to identify wells that appeared to be constrained. Data will be presented documenting specific cases of inter-well and inter-zonal communication. This will include both offset wells that had been on production prior to the fracturing treatment and offset wells that had been recently drilled.
Extended sampling of individual fluid tracers can be an extremely useful tool in explaining production anomalies as they occur. On this project, the operator was able to identify the source of production changes and determine the best well intervention technique to economically increase production.
Measurement of Gas Diffusivity in Heavy Oils/Bitumens using Pressure-Decay Test
Authors: Ratnakar Ram R. , Dindoruk Birol 
Published: October 2014

Abstract
Molecular diffusion plays a very important role in various reservoir processes; especially in the oil recovery processes where convective forces are not dominant or when direct frontal contact and mixing is not possible. For example, in heavy oil and bitumen recovery, injected light hydrocarbons can diffuse into the oil beyond the potential fronts and/or convective zones and promote the effectiveness of the displacement process, and therefore, reduce in-situ viscosities which in turn enhance the oil recovery.
Similarly, diffusive mixing can also be a dominant mechanism in the gas re-dissolution process even in lighter hydrocarbon systems. For example, it controls how much gas will be dissolved in oil and how long it will take to dissolve, in the absence of mechanical/convective mixing, as in the case of reservoir re-pressurization. The extent of dissolution of a gas into oil is governed by its solubility but the rate is controlled by molecular diffusivity and solubility, both. Thus accurate determination of these parameters is essential to design and understand displacement processes.
Despite the significance of diffusion in various aspects of oil recovery, there are very few experimental studies available in the literature addressing the diffusion of gas in heavy oils. Experimental work is most commonly based on the Pressure-decay concept. However, the parameter inversion in these tests relies on an error function solution that neglects the transient processes at the gas-oil interface and assumes constant saturation concentration. This assumption is not appropriate because pressure in the gas cap changes continuously as gas is dissolved in the oil and hence the gas solubility varies with time. One of the major issues related to this experimental process is that it takes a long time (order of several days to few months) to achieve steady state (converged) solution to determine diffusivity.
In this work, we have
Experimentally investigated the diffusion of methane in heavy oils as well as light oils using pressure-decay test; Captured the transient effect at the gas-oil interface transient properly by expressing gas solubility in terms of Henry's constant in the model (1-dimensional diffusion equation coupled with pressure decline due to gas dissolution); Developed the exact solution of the model and shown that after long time, pressure decays exponentially in time with an exponent that depends on diffusivity as well as solubility; Presented the inversion technique, determined the diffusivity and other parameters from late transient pressure data, and showed the convergence in their estimates; and, Most importantly, we have developed a cut off criterion permitting us to stop the experiments while still being able to extract the converged diffusivity values (this is important in situations when the experiment is stopped prematurely for technical or other reasons).
Developing a Fatigue Risk Management System: Case Studies on Education and Mitigation Strategies
Authors: Acton Sarah 
Published: October 2014

Abstract
"Fatigue" is neither easy to define nor measure. Symptoms include a lack of alertness and reduced mental and physical performance but identifying these symptoms can be challenging. Despite the difficulty of recognizing the symptoms of fatigue, they have in fact contributed to many major accidents in numerous safety-critical industries. Due to the safety-critical environment of industries, such as oil and gas, fatigue can lead to catastrophic consequences when symptoms begin to affect works' decision-making capabilities. Implementing a Fatigue Risk Management System can help reduce worker fatigue and improve situation awareness, especially during shifts with high risk of fatigue.
A successful system which eliminates emerging symptoms and prevents overexaustion includes two main focus areas for eliminating or mitigating the effects of fatigue: fatigue education for workers and on-duty alertness strategies. Understanding the human body and how environmental factors can affect sleep are important to helping workers achieve and maintain good sleep hygiene. Employing fatigue alertness strategies, especially during night shifts, is crucial to helping employees stay alert and focused during high-workload tasks. This paper will explore fatigue education and mitigation strategies in various industries to determine what factors contribute to a successful Fatigue Risk Management System.
Foams Stabilized by In-Situ Surface Activated Nanoparticles in Bulk and Porous Media
Authors: Singh Robin , Mohanty Kishore K. 
Published: October 2014

Abstract
The goal of this work is to study foam stabilization by in-situ surface activation of hydrophilic nanoparticles for subsurface applications. The interfacial properties of the nanoparticles were modulated by attachment of short chain surface modifiers which render them partially hydrophobic. Static foams were generated using nanoparticles with varying concentrations of surface modifiers. The decay of foam height with time was studied and half-lives were determined. Optical micrographs of foams stabilized by surface-modified nanoparticles (SM-NP) and surfactants were recorded. Aqueous foams were created in-situ by co-injecting the SM-NP solutions with nitrogen gas through a Berea sandstone core at a fixed quality. Pressure drop across the core was measured to estimate the achieved mobility reduction factor (MRF). The results were then compared witha typical surfactant under similar conditions. Oil displacement experiments were conducted in Berea cores using surfactant and SM-NP solutions as foaming agents. Bartsch shake test revealed strong foaming tendency of SM-NP even with a very low initial surface-modifier concentration (0.05 wt%), whereas hydrophilic nanoparticles alone could not stabilize foam. The bubble texture of foam stabilized by SM-NP was finer than that with surfactant which indicated a stronger foam. As the degree of surface coating increased, mobility reduction factor (MRF) of SM-NP foam in a Berea core increased significantly. The core floods in the sandstone cores with a reservoir crude oil showed that immiscible foams using SM-NP solution can recover significant amount of oil over water flood.
Modeling Adsorption of Gases in Nanoscale Pores Using Grand Canonical Monte Carlo Simulation Techniques
Authors: Al Ismail Maytham I. , Horne Roland N. 
Published: October 2014

Abstract
Shale gas and liquid-rich shales have become important energy sources in the US and other parts of the world. Shale rocks contain a very heterogeneous pore system. The pore size varies between micro-, meso- and macroscales. One critical phenomenon that governs the flow of hydrocarbons and is strongly affected by pore size is the adsorptive behavior. The adsorbate packing and density is influenced strongly by the force fields of the closely opposing pore walls.
In this study, molecular simulation was applied to generate adsorption isotherms of pure methane, pure n-butane and methane/n-butane mixtures using grand canonical Monte Carlo (GCMC) techniques. The simulations were conducted on a slit pore model composed of parallel planar graphitic surfaces. Various pore sizes were studied ranging from 1 nm to 20 nm. The nonbonded interactions between the molecules, as well as between the molecules and the pore walls were described with Lennard-Jones potentials. To verify the model, the simulated adsorption isotherms were compared with adsorption isotherms obtained from published experimental data where the adsorption measurements of methane and n-butane were conducted on a Marcellus shale sample and carbon materials; respectively.
In the pure molecule cases, results indicate that as the pore width increases, the density of the adsorbed molecules decreases due to the reduction of the fluid-wall interaction. For example, above 10 nm pore-width, the density of methane inside the slit pore becomes comparable to the methane density in the bulk. In the methane/n-butane mixture case, results indicate that the selectivity of n-butane over methane was greater than 1 at low pressures (~200 psi). Therefore, n-Butane is the more favorable component to adsorb and form a layer near the pore walls. However, at high pressures (~1,000 psi), "selectivity reversal" was observed due to size entropy effects. Preferential adsorption leads to compositional variations in the gas produced from the shale.
This study provides insights on the adsorptive behavior of light and heavy hydrocarbon molecules. Determining the effect of fluid confinement on adsorption will lead to better understanding of the fluid behavior in rocks with nanoscale pores such as shales. This is especially important when the compositional behavior of confined multicomponent gas-condensate mixtures is investigated during depletion to develop strategies for more effective hydrocarbon recovery.
A Guideline to Calculate Erosional Velocity due to Liquid Droplets for Oil and Gas Industry
Authors: Arabnejad H. , Shirazi S. A. , McLaury B. S. , Shadley J. R. 
Published: October 2014

Abstract
In the oil and gas industry, pipe size and material are selected so that the flow velocity is below the so called "erosional velocity," presumably a flow velocity at which it is safe to operate. The American Petroleum Institute Recommended Practice 14E (API RP 14E) guide describes a method for calculating an erosional velocity for clean service. For oil and gas industry applications, some authors assume that the basis for API RP 14E is erosion due to liquid droplet impact. However, there is no experimental or theoretical evidence supporting this idea. The goal of present work is to provide a guideline to calculate erosional velocity due to liquid droplets in oil and gas production and transportation facilities. This paper describes how liquid droplet erosion can be calculated for a variety of materials that are commonly used in oil and gas industry pipelines. The calculation methodology developed previously has been extended to predict erosion of the oilfield materials due to water droplets with and without impurities using experimental data that was collected for specimens impacting a liquid jet. The erosion equation for liquid impact presented in American Society for Testing and Materials (ASTM) standard G73-10 has been modified based on experimental data to consider velocity exponent changes with droplet size. Based on the new erosion model, a procedure has been developed to predict erosional velocity due to liquid droplet impact utilizing the entrainment fraction and droplet size calculated from two-phase flow correlations and the impact velocity of the droplets within a pipe elbow or a tee that is estimated using stagnation length model which is basically a one-dimensional particle tracking model and an alternative for complex Computational Fluid Dynamic (CFD) simulation of multiphase flow and incorporated particle tracking scheme. Experimental data that was obtained at the Erosion/Corrosion Research Center (E/CRC) for several engineering materials such as stainless and carbon steels, chromium alloys and Inconel are used to calculate a threshold velocity using the data and method developed in this study. The erosional velocities computed using this model are compared with the erosional velocities computed using API RP 14E. It is shown that the trend of the erosional velocity calculated by the API guideline is extremely conservative as compared to the new model predictions for erosion due to liquid impact and does not correlate with erosion due to small entrained particles. Thus, oil and gas producers can use this method and provided equations and graphs to determine erosional velocities for cases when no sand is being produced or when small particles are entrained in the liquid.
A Mechanistic Model for Wettability Alteration by Chemically Tuned Water Flooding in Carbonate Reservoirs
Authors: Qiao C. , Li L. , Johns R. T. , Xu J. 
Published: October 2014

Abstract
Injection of chemically tuned brines into carbonate reservoirs has been reported to enhance oil recovery by 5% to 30% OOIP in core flooding experiments and field tests. One proposed mechanism for this improved oil recovery (IOR) is wettability alteration of rock from oil wet or mixed-wet to more water wet conditions. Modeling of wettability alteration experiments, however, are challenging due to the complex interactions among ions in the brine and crude oil on the solid surface. In this research, we developed a multiphase multicomponent reactive transport model that explicitly takes into account wettability alteration from these geochemical interactions in carbonate reservoirs.
Published experimental data suggests that desorption of acidic oil components from rock surfaces make carbonate rocks more water wet. One widely accepted mechanism is that sulfate (SO42−) replaces the adsorbed carboxylic group from the rock surface while cations (Ca2+, Mg2+) decrease the oil surface potential. In the proposed mechanistic model, we used a reaction network that captures the competitive surface reactions among carboxylic groups, cations, and sulfate. These reactions control the wetting fractions and contact angles, which subsequently determine the capillary pressure, relative permeabilities, and residual oil saturations.
The developed model was first tuned with experimental data from the Stevns Klint chalk and then used to predict oil recovery for additional un-tuned experiments under a variety of conditions where IOR increased by as much as 30% OOIP, depending on salinity and oil acidity. The numerical results showed that an increase in sulfate concentration can lead to an IOR of over 40% OOIP, while cations such as Ca2+ have a relatively minor effect on recovery (about 5% OOIP). Other physical parameters, including the total surface area of the rock and the diffusion coefficient, control the rate of recovery, however not the final oil recovery. The simulation results further demonstrate that the optimum brine formulation for chalk are those with relatively abundant SO42− (0.096 mol/kg water), moderate concentrations of cations, and low salinity (total ionic strength less than 0.2 mol/kg water). These findings are consistent with the experimental data reported in the literature. The new model provides a powerful tool to predict the IOR potential of chemically tuned waterflooding in carbonate reservoirs under different scenarios.