bluuebunny/crossref_metadata_2025_split huggingface dataset:
Estimation of Foam Flow Parameters for Local-Equilibrium Methods using Steady-State Flow Experiments and Optimization Algorithms
Authors: Cavalcante Filho Jose Sergio , Delshad Mojdeh , Sepehrnoori Kamy 
Published: March 2016

Abstract
In this paper, we estimate foam parameters and investigate foam behavior for a given range of water saturation using two local equilibrium foam models: the population balance and the Pc*. Our method uses an optimization algorithm to estimate foam model parameters by matching foam measured pressure gradient from steady-state coreflood experiments. We calculate the effective foam viscosity and the water fractional flow using experimental data and we then compare lab data against results obtained with the matched foam models to verify the foam parameters. Other variables, such as the foam texture and foam relative permeability are used to further investigate the behavior of the foam during each experiment. We propose an improvement to the Pc* model with a better match in high quality regime by assuming resistance factor and critical water saturation is a linear function of pressure gradient. Results show that the parameter estimation method coupled with an optimization algorithm successfully matches the experimental data using both foam models. In the population balance, we observe different values of the foam effective viscosity for each pressure gradient due to variations of the foam texture and shear thinning viscosity effect. The Pc* model presents a constant effective viscosity for each pressure gradient; we propose the use of resistance factor and critical water saturation as a linear function of pressure to improve the match in the high quality regime, when applicable. Foam has been successfully used in the oil industry for conformance and mobility control in gas injection processes. The efficiency of a foam injection project must be assessed by means of numerical models. Although there are several foam flow models in the literature, the prediction of foam behavior is an important issue that needs further investigation.
Polymer Flooding Economics, from Pilot to Field Implementation at the Example of the 8 TH Reservoir, Austria
Authors: Sieberer Martin , Jamek Karl , Clemens Torsten 
Published: March 2016

Abstract
As polymer injection has not reached the same maturity as waterflooding, implementing polymer injection projects at field scale requires a workflow comprising screening of the portfolio of an organization for oil fields potentially amenable for polymer injection, laboratory and field testing followed by sector- and field implementation and roll-out in the portfolio.
Going through the workflow, not only the subsurface uncertainty is reduced but also the knowledge about the cost structure and operating capabilities of the organization improved.
Analyzing the economics of polymer injection projects shows that costs can be split into polymer injector-producer (polymer pattern) dependent and independent costs. Knowing these costs, a Minimum Economic Number of Patterns (MENP) is defined to achieve Net Present Value zero. This number is used to determine a Minimum Economic Field Size (MEFS) for polymer injection which is taken into account in the screening of the portfolio.
Defining a robustness criterion for economics, the minimum number of patterns for polymer injection meeting this criterion is calculated. This criterion is applied to generate a diagram allowing for screening of fields for polymer economics using pattern dependent and pattern independent costs and Utility Factor.
The cost structure reveals how the NPV of polymer projects changes with number of patterns, incremental oil and injectivity. Injectivity is of particular importance as it determines the Chemical Affected Reservoir Volume (CARV) or speed of production.
A sensitivity analysis of the NPV showed that for the cost structure used here, in addition to the polymer costs, the well costs are important for the economics of a full-field polymer injection project.
Effective Extraction of Green River Oil Shale via Combustion
Authors: Kar Taniya , Hascakir Berna 
Published: March 2016

Abstract
The Green River, Utah holds the world's greatest oil shale resources. However, the hydrocarbon, which is namely kerogen, extraction from shales is limited due to environmental and technical challenges. In this study, we investigated the effectiveness of the combustion process for shale oil extraction. Samples collected from the Green River formation were first characterized by X-ray Diffraction (XRD) and Scanning Electron Microscopy (SEM). Then, series of dry combustion tests were conducted at different heating rates and wet combustion tests by water addition. The combustion efficiency was enhanced by mixing oil shale samples with an iron based catalyst. The effectiveness of dry, wet, and catalyst added combustion processes was examined by the thermal decomposition temperature of kerogen. Because the conventional oil shale extraction methods are pyrolysis (retorting) and steaming, the same experiments were conducted also under nitrogen injection to mimic retorting. It has been observed that the combustion process is a more efficient method for the extraction of kerogen from oil shale than the conventional techniques. The addition of water and catalyst to combustion has been found to lower the required temperature for kerogen decomposition for lower heating rate. This study provides insight for the optimization of the thermal methods for the kerogen extraction.
Determination of Individual Diffusion Coefficients of C3H8–n-C4H10-CO2-Heavy Oil Systems at High Pressures and Elevated Temperatures by Dynamic Volume Analysis (DVA)
Authors: Zheng Sixu , Yang Daoyong 
Published: March 2016

Abstract
By coupling heat and mass transfer for C3H8–n-C4H10-CO2-heavy oil systems as well as by treating heavy oil as multiple pseudocomponents, a new method and its computational scheme has been developed to determine individual diffusion coefficients of alkane solvents and CO2 in heavy oil at high pressures and elevated temperatures by dynamic volume analysis (DVA). Experimentally, well-designed diffusion tests have been conducted for an n-C4H10-heavy oil system, a CO2-heavy oil system, an n-C4H10-CO2-heavy oil system, and a C3H8–n-C4H10-CO2-heavy oil system by using a visualized PVT setup, respectively. The volume change of liquid phase is monitored and recorded during the measurements, while the gas chromatography method is employed to determine the compositions of gas mixtures at the beginning and the end of the diffusion tests, respectively. Theoretically, the volume-translated Peng-Robinson equation of state with characterizing heavy oil as multiple pseudocomponents has been incorporated to develop a two-dimensional heat and mass transfer model for the aforementioned systems. The alternating direction implicit (ADI) algorithm is applied to solve the two-dimensional difference equations into which a moving gas-liquid interface has been successfully incorporated. The discrepancy between the measured and calculated dynamic volume change and the discrepancy between the measured and calculated gas compositions at the end of diffusion tests have been minimized to determine the individual diffusion coefficients. Alkane solvents diffuse faster than CO2 in heavy oil, while addition of alkane solvent(s) into CO2 stream not only enhances mass transfer, but also achieves an improved swelling effect of heavy oil. Among the four diffusion tests, the largest dynamic swelling factor at the end of diffusion test is measured to be 1.118 for the C3H8–n-C4H10-CO2-heavy oil system.
Experimental Study of Nanocatalytic In-Situ Upgrading for Heavy Oil Production From Naturally-Fractured-Carbonate Reservoirs
Authors: Suarez Ricardo G. , Scott Carlos E. , Pereira-Almao Pedro , Hejazi S. Hossein 
Published: March 2016

Abstract
Nanocatalytic in-situ upgrading is a novel oil recovery method that involves chemical, thermal and miscible processes. In this work the main oil recovery mechanisms of nanocatalytic in-situ upgrading were studied, particularly the ones that promote additional oil production from low matrix permeability blocks.
Heavy oil recovery from Silurian dolomite cores was studied using a cylindrical core holder set-up. Fractures in the system were represented by a gap between the core sample and core holder wall. Oil recovery experiments were conducted in batch-mode using hydrogen and a trimetallic nano-catalyst. The cores were fully saturated with heavy-oil and the fractures were filled with hydrogen and vacuum residue with ultra-dispersed nano-catalyst at 300 °C and 1000 psig. The produced oil from the matrix was collected and the recovery factor for each experiment was calculated. Moreover, the residual oil in the core was extracted using a solvent. Both samples (i.e., produced and residual oil) were characterised by laboratory measurements and analytical techniques in order to assess oil quality distribution.
Experimental results revealed a significant increment in oil recovery with hydrogen injection. This increment suggests that during nanocatalytic in-situ upgrading oil is produced due to the presence of hydrogen in gas form. Results also demonstrated that, by use of an ultra-dispersed Ni-W-Mo nano-catalyst, the oils contained in both the fracture and matrix, were upgraded.
This research fosters the understanding of the main recovery mechanisms from carbonate matrix blocks by use of nanocatalytic in-situ upgrading. This study contributes to better understanding a recovery technique that will unlock heavy-oil resources contained in carbonate rocks.
Understanding Selective Plugging and Biofilm Formation of a Halophilic Bacterial Community for MEOR Application
Authors: Klueglein Nicole , Kögler Felix , Adaktylou Irini J. , Wuestner Marina L. , Mahler Eva , Scholz Justus , Herold Andrea , Alkan Hakan 
Published: March 2016

Abstract
MEOR (microbial enhanced oil recovery) is known as one of the emerging low-cost EOR technologies, which uses in-situ microorganisms living in the oil field. Some of the most promising microbial-induced mechanisms include production of extracellular polymeric sugars (EPS), biofilms as well as selective plugging caused by cell growth. However, there is limited data available concerning the way microbes and biofilms behave in contact to surfaces in porous media in the context of MEOR. The aim of this work was to investigate bacterial growth and biofilm production in the framework of an ongoing MEOR project conducted by Wintershall and BASF. We used various approaches to investigate cell behavior of a halophilic bacterial community derived from a Wintershall oil field. Bacterial growth was conducted in both batch cultures and under dynamic conditions. To visualize cell adhesion and also exopolymers occuring in biofilms we used specific fluorescent dyes. During incubation of the microbes over several weeks we could visualize different types of EPS under the microscope. This observation fits perfectly to a concurrent viscosity increase of the surrounding media. Modelling approaches were applied to estimate the potential contribution of these effects on additional oil recovery. The observations including cell clumping, sorption and polymer production were geometrically quantified and the effect of the modifications on permeability profile and resulting flow characteristics was numerically investigated with fluid dynamic simulations of the petrophysical changes. The potential implications of the observed changes on EOR capability by conformance control and wettability modification were further estimated with analytical approaches. With the developed methods for visualization and modelling of the microbes and biofilms in both batch and dynamic conditions, we are able to monitor the clumping and sorption behavior of the cells, which will help to interprete data obtained during an upcoming MEOR field trial.
Salinity-Sensitive Polymeric Particles for EOR
Authors: Panthi Krishna , Mohanty Kishore K. 
Published: March 2016

Abstract
The goal of this research is to improve oil recovery by reducing bypassing due to fractures, common in carbonate reservoirs. Salinity sensitive polymeric particles (SSPP) are synthesized in this study, which can plug fractures in reservoir rocks and divert fluid flow into the matrix. SSPP swell in brine; the swelling is a function of brine salinity. SSPP expand many times (~70 times) in DI water, but swell only about 3 times in very high salinity (20 wt% NaCl) brine. The swelling of the particles is independent of pH in the range of 2 to 12.6. The swelling process is reversible with salinity. These particles are stable at 60 °C for at least several months. Core flood results show that these small particles can be transported through fractures during high salinity brine injection and plug the fractures during low salinity brine injection. Then the injectant fluid flow is diverted into the matrix and recovers oil from previously unswept matrix. SSPP injection increases waterflood recovery in cores with full fractures and half fracture connected to the inlet. The SSPP placement also increases oil recovery for tertiary miscible floods.
Nanoparticle Stabilized CO2 Foam: Effect of Different Ions
Authors: San Jingshan , Wang Sai , Yu Jianjia , Lee Robert , Liu Ning 
Published: March 2016

Abstract
This paper reports the study of the effect of different ions (monovalent, bivalent, and multiple ions) on nanosilica-stabilized CO2 foam generation. CO2 foam was generated by co-injecting CO2/5,000 ppm nanosilica dispersion (dispersed in different concentrations of brine) into a sandstone core under 1,500 psi and room temperature. A sapphire observation cell was used to determine the foam texture and foam stability. Pressure drop across the core was measured to estimate the foam mobility. The results indicated that more CO2 foam was generated as the NaCl concentration increased from 1.0% to 10%. Also the foam texture became denser and foam stability improved with the NaCl concentration increase. The CO2 foam mobility decreased from 13.1 md/cp to 2.6 md/cp when the NaCl concentration increased from 1% to 10%. For the bivalent ions, the generated CO2 foam mobility decreased from 19.7 md/cp to 4.8 md/cp when CaCl2 concentration increased from 0.1% to 1.0%. Synthetic produced water with total dissolved solids of 17,835 ppm was prepared to investigate the effect of multiple ions on foam generation. The results showed that dense, stable CO2 foam was generated as the synthetic produced water and nanosilica dispersion/CO2 flowed through a porous medium. The lifetime of the foam was observed to be more than two days as the foam stood at room temperature. Mobility of the foam was calculated as 5.2 md/cp.
Low Salinity Flooding Trial at West Salym Field
Authors: Erke S. I. , Volokitin Y. E. , Edelman I. Y. , Karpan V. M. , Nasralla R. A. , Bondar M. Y. , Mikhaylenko E. E. , Evseeva M. 
Published: March 2016

Abstract
Low-salinity waterflooding (LSF) has been recognized as an IOR/EOR technique for both green and brown fields in which the salinity of the injected water is lowered for particular reservoir properties to improve oil recovery. While providing lower or similar UTC's low salinity projects have the advantage of lower capital and operational costs as compared to some more expensive EOR alternatives.
This work describes LSF experiments, field-scale simulation results, and conceptual design of surface facilities for West Salym oil field. The field is located in West Siberia and is on stream since 2004. Conventional waterflooding was started in 2005 and current water cut is currently above 80% in the developed area of the field. To counter oil production decline a tertiary Alkaline-Surfactant-Polymer (ASP) flooding technique selected for mature waterflooded field parts and piloting of this technique is ongoing. Operationally simpler and more cost-effective LSF method is considered for implementation in the unflushed (green) areas of the field since it has been recognized that application of LSF in secondary mode results in better incremental oil recovery than LSF in tertiary mode.
The results of a comprehensive conceptual study performed to justify the LSF trial are presented in this paper. To generate production forecast for LSF in the isolated area at the outset of reservoir development the results of laboratory core tests executed at different salinities presented earlier (Suijkerbuijk et al., 2014) have been used. Dynamic reservoir modelling using low-salinity relative permeability curves showed that injection of low-salinity water leads to incremental oil production up to 2.5% of STOIIP. These results establish the fundamentals for a LSF field trial. A concept of surface facilities design for LSF trial area at West Salym oil field is also presented in the paper. Differently to other LSF projects it is proposed to prepare low-salinity water with required properties by mixing fresh water from aquifer and high salinity water from produced water reinjection (PWRI) system. In such a case LSF facilities concept does not require expensive water treatment techniques which significantly reduces the project capital and operational costs.
Reservoir Management in Howard-Glasscock Field: Waterflood Redevelopment in a 90 Year Old Field
Authors: Smith Cameron , Chapman Shay , Lopez Jorge 
Published: March 2016

Abstract
This paper presents the integrated approach for the redevelopment of the waterflood in Howard-Glasscock field located primarily in Howard County, Texas. Originally discovered in 1925, the majority of production is now commingled across the Guadalupe, Glorieta and Clearfork formations. This is a mature field which is currently in the midst of a 5 and 10 acre infill drilling program that began in 2009. Emphasis has primarily been focused on drilling producing wells, but the basis for this project was to optimize an existing waterflood to guide the development strategy of the field moving forward.
A study of the production of the wells drilled since 2009 identified stronger performance in wells with offset waterflood support. On average, waterflood was responsible for a 22% improvement in the expected recovery per well, despite a lack of patterns or a comprehensive waterflood management plan. As a result, a multi-disciplined team was commissioned to design a strategy for the redevelopment of the flood and more active management of the daily operations. Geology and reservoir engineering aspects were used to characterize the reservoir in conjunction with classical waterflood methods to understand the current performance and validate the expectations for secondary recovery.
Fracture orientation was studied based on cases of early breakthrough and was utilized in pattern identification and well placement to maximize sweep and discourage direct communication between injectors and producers. Further, the success of the waterflood in Howard-Glasscock relies on the ability to control the flow of water over a 2,000 foot vertical interval. To address this, the team has implemented a surveillance plan with improved monitoring and communication with the operations team to enhance the collection of data and in order to react to the dynamics of a waterflood. The rapid response to injection observed in this field requires proper surveillance and timely control of water flow which ultimately drives the success of the program by moving water from high water cut intervals to bypassed oil zones.
This paper details the systematic approach that was used to design the redevelopment plan for a waterflood in a 90 year old field. The scope of work is being implemented and represents an adjustment in the development plan of Howard-Glasscock moving forward. Ultimately, the enhanced performance observed in recent drilling programs and the continued success of development in this mature field hinges on understanding and managing the waterflood moving forward.
Nanoparticle-Stabilized Natural Gas Liquid-in-Water Emulsions for Residual Oil Recovery
Authors: Griffith Nicholas , Ahmad Yusra , Daigle Hugh , Huh Chun 
Published: March 2016

Abstract
Interest in silica nanoparticle-stabilized emulsions, especially those employing low-cost natural gas liquids (NGLs), has increased due to recent developments suggesting their use leads to improved conformance control and increased sweep efficiencies. When compared to conventional emulsion- stabilizing materials such as surfactants, nanoparticles are an inexpensive and robust alternative, offering stability over a wider range of temperature and salinity, while reducing environmental impact.
Oil-in-water emulsions with an aqueous nanoparticle phase and either a pentane or butane oil phase at a 1:1 volume ratio were generated at varying salinities for the observations of several emulsion characteristics. The effects of salinity on the stability of silica nanoparticle dispersions and NGL emulsions were observed. Increasing the salinity of the aqueous nanoparticle phase resulted in an increase in effective nanoparticle size due to increased nanoparticle aggregation. Rheology tests and estimates of emulsion droplet sizes were performed. Shear-thinning behavior was observed for all emulsions. Furthermore, overall emulsion viscosity increased with salinity. Nanoparticle-stabilized liquid butane-in-water emulsions were also generated with varying brine concentrations; however, no rheology or droplet size measurements were made due to the volatility of these emulsions.
Residual oil recovery coreflood experiments were conducted (using Boise Sandstone cores) with nanoparticle-stabilized pentane-in-water emulsions as injectant and light mineral oil as residual oil. A recovery of up to 82% residual oil was observed for these experiments. By continuously measuring the pressure drop across the core, a possible mechanism for enhanced oil recovery is proposed. Pentane emulsion coreflood tests indicated that at a slower injection rate, residual oil recovery increases. This contrasts viscous emulsion corefloods (mineral oil or Texaco white oil as the emulsion oil phase), where increasing the injection rate increases the residual oil recovery.