bluuebunny/crossref_metadata_2025_split huggingface dataset:
Micro-Scale Experiment and CFD Modeling of Viscoelastic Polymer; Trapped Oil Displacement and Deformation at the Dead-End
Authors: Afsharpoor Ali , Ma Kun , Mateen Khalid , Duboin Aurélien , Jouenne Stephane , Cordelier Philippe 
Published: June 2014

Abstract
Polymers are used in enhanced oil recovery (EOR) to control the mobility ratio between displaced fluid (oil) and displacing fluids (water). Polymer improves sweep efficiency by overcoming gravity overriding, viscous fingering, and channeling. For many years, improving sweep efficiency was considered the only significant mechanism to increase the oil recovery in polymer-flooding. But recently, experimental and field data suggest that viscoelastic polymers such as hydrolyzed polyacrylamide (HPAM) improve displacement efficiency as well and reduce the residual oil saturation. One of the hypotheses is that the elasticity of polymer triggers the pulling-effect on the trapped oil at the dead ends, thus leading to the mobilization of the trapped oil.
In this study, micro-scale experiments were done to prove or disprove the hypothesis of viscoelasticity pulling-effect. Then, steady-state (static) CFD modeling was performed in the dead ends of the porous medium to analyze the flow characteristics of viscoelastic polymer. The streamlines, velocity contours, and normal stress contours are discussed here. Both, experimental work and steady-state simulation results show that the oil can be barely mobilized in normal reservoir condition mimicked by the micro-scale experiments.
Additionally, transient (dynamic) CFD modeling was carried out for a better understanding of oil droplet movement and deformation at dead-end geometry. The Arbitrary Lagrangian-Eulerian (ALE) finite-element formulation is used to keep track of interface between oil and the displacing fluid. The dynamic simulation results are in agreement with static simulation and experimental results. This study shows that with normally used viscoelastic polymers, the pulling-effect is not the main mechanism resulting in reduced residual oil saturation. However, ways increasing of the Deborah number through potential means, such as using polymer with higher relaxation time, may result in a more significant pulling effect and thereby recover residual oil.
Switchable Amine Surfactants for Stable CO2/Brine Foams in High Temperature, High Salinity Reservoirs
Authors: Elhag Amro S. , Chen Yunshen , Chen Hao , Reddy Prathima P. , Cui Leyu , Worthen Andrew J. , Ma Kun , Hirasaki George J. , Nguyen Quoc P. , Biswal Sibani L. , Johnston Keith P. 
Published: June 2014

Abstract
Ethoxylated amine surfactants of the form C12-14N(EO)x have been characterized for foam generation to improve the sweep efficiency for CO2 enhanced oil recovery (EOR) up to 120 °C in the presence of high salinity brine of 22%TDS. These surfactants are switchable from the nonionic (unprotonated amine) state in dry CO2 to cationic (protonated amine) in the presence of an aqueous phase with a pH below 6. Potentiometric titration of two surfactants with 2 or 15 EO groups was conducted at 90 °C to test the switchability of the surfactant from nonionic to cationic forms at different pH values. Ethoxylated amine with 2 EO groups showed more affinity for protonation when compared to 15 EO due to the hinderance effect of the larger molecule that covers the ionizable nitrogen head. For C12-14N(EO)2, viscous C/W foams were produced by injecting the surfactant either in the CO2 phase or the brine phase, which indicates good surfactant transport to the interface in either case. The optimum foam quality was observed at 90% and 95% when the surfactant was injected from brine phase or CO2 phase, respectively. C12-14N(EO)2 was effective in lowering the interfacial tension between water and CO2 at 120 °C and 22%TDS from ~ 40 mN/m to 5 mN/m with CMC value of 0.038 mM. This significant reduction in interfacial tension enhances foam generation and foam stability.
Listening to the Data: An Analysis of the Oil and Gas Journal Database
Authors: Lake Larry W. , Yang Andrew , Pan Zhong 
Published: June 2014

Abstract
The Oil and Gas Journal (OGJ) biennial survey on EOR projects has been a partner to the IOR Symposium since early time. Plots of EOR projects versus time, taken from the survey, have been a mainstay of plenary talks. But there is much more to be learned in the database, and the purpose of this work is to find out what can be learned from a broad analysis.
The paper uses standard statistical techniques to infer binary correlations between data sets. With fewer than 300 US projects, the analysis by no means meets the standards of Big Data, but there are things to be learned, nevertheless, because of the scope of survey: It includes all projects worldwide, surveys since 1986, and covers all EOR processes. However, some processes are more represented in the surveys than others, so these are analyzed in the most detail.
We also perform more sophisticated analysis using the conditional probability theorem to infer the probability of success of steam EOR projects. We look at the OGJ survey from the view of screening as exemplified in the work of Taber et al. (1997), and updated by Dickson et al. (2010). In one sense our work is basically an attempt to see how well these guidelines have been followed in practice.
Single Well Pilot Test of Near Miscible CO2 Injection in a Kansas Arbuckle Reservoir
Authors: Tsau J. S. , Ballard M. 
Published: June 2014

Abstract
A recent study showed that CO2 injection at pressures below minimum miscibility pressure (MMP) improves oil recovery with Arbuckle reservoir core samples at near miscible conditions. To demonstrate its applicability on a larger scale, a single well pilot test was designed to experimentally inject CO2 into the Arbuckle formation at pressures below MMP to determine the efficiency of CO2 displacement at near miscible conditions.
The pilot test consists of a single-well chemical tracer (SWCT) test before and after CO2 injection on a selected well producing from the Arbuckle formation. The reservoir operating pressure was 1,150 psi while the MMP of the oil was 1,500 psi at 106 °F (reservoir temperature). The first chemical tracer test was performed to determine the oil saturation in the formation prior to CO2 injection. This was followed by injecting approximately 17 tons of CO2 at pressures below MMP with a follow up water displacement, followed by a second tracer test performed to determine the remaining oil saturation.
The oil saturation measured from the two tracer tests were 0.23 and 0.20, respectively. A reduction of oil saturation by 0.03 represents a 13% improvement of oil displacement which results from CO2 injection at near miscible conditions. The test results indicate the potential of using near miscible CO2 to improve oil recovery in Kansas Arbuckle reservoirs and others where MMP cannot be achieved.
Evaluation of Surfactants for Oil Recovery Potential in Shale Reservoirs
Authors: Nguyen Duy , Wang Dongmei , Oladapo Aderaje , Zhang Jin , Sickorez Jeffrey , Butler Ray , Mueller Brian 
Published: June 2014

Abstract
Most shale reservoirs (e.g., Bakken Shale and Eagle Ford) have a low permeability, low porosity, and oil-wet character with natural fractures. As a result, the oil recovery factors are very low, only a few percent of original oil in place. Injection of water into oil-wet reservoirs (i.e., water flooding) is not effective due to small or negative capillary pressure. In this study, various surfactants (non-ionic, cationic, anionic, and amphoteric) were studied for spontaneous imbibition into oil-wet shale cores. Surfactant imbibition into Eagle Ford shale outcrop cores and Bakken reservoir cores increased oil recovery compared to brine only. Oil recovery can be seen for surfactants that alter the reservoir from oil-wet to water-wet. For example, the incremental oil recovery was about 24% % for 0.1% cationic surfactant and 57% for 0.1% nonionic surfactant. The goal of this work is to investigate the effect of salinity, surfactant concentration, electrolyte concentration, and temperature on the wettability alteration and provide mechanisms. Contact angles and interfacial tensions (IFT) were measured and correlated with spontaneous imbibition. Wettability alteration from oil-wet to water-wet (i.e., low contact angle) appeared to be more important than a low interfacial tension in increasing the oil recovery rate from fractured oil-wet reservoirs, especially for nonionic surfactants and amphoteric surfactants. Wettability alteration is maximum and IFT is minimum for anionic and cationic surfactants at an optimal salinity. However, as the reservoir salinity increases, the maximum wettability alteration decreases and IFT increases.
Study Nanoparticle-Stabilized CO2 Foam for Oil Recovery at Different Pressure, Temperature, and Rock Samples
Authors: Mo Di , Jia Bao , Yu Jianjia , Liu Ning , Lee Robert 
Published: June 2014

Abstract
This paper presents a series of studies the nanoparticle-stabilized CO2-foam for waterflooded residual oil recovery. Nanosilica-stabilized CO2 foam has been observed to improve oil recovery after waterflooding in sandstone. The effects of pressure, temperature, and rock samples on the performance of CO2 foam on residual oil recovery were investigated. The results indicated that the residual oil recovery (percent of waterflooded residual oil) by CO2/nanosilica flooding increased from 64.9% to 75.8% when the pressure was increased from 1,200 psi to 2,500 psi. When temperature increased from 25°C to 60°C, the residual oil recovery by CO2/nanosilica flooding decreased from 62.6% to 52.1%. The particle-stabilized CO2 foam was also observed to improve oil recovery from limestone and dolomite after waterflooding. The results also suggested that particles plugging-in probably occurred in dolomite during the CO2 foam core flooding test.
New Insights on the Role of Multivalent Ions in Water-Carbonate Rock Interactions
Authors: Kwak Hyung T. , Yousef Ali A. , Al-Saleh Salah 
Published: June 2014

Abstract
The current study is focused on the effects of the individual key ions (Ca2+, Mg2+, (SO4)2-) along with a few of other common ions (Na+ and Cl-) on carbonate rock by only injecting water with controlled amount of individual or combined ions into the selected carbonate rock at reservoir temperature. A low field NMR technique has been a tool of choice for the current work since it allows monitoring the physical and chemical alteration of rock surface after interacting with fluids which contain specific types and amount of ions. In addition, since NMR is non-destructive measurement, the effect of various types of fluids with the identical rock sample before, during, and after core flooding test can be monitored repeatedly.
NMR results indicate that the water-rock interaction changes when injecting different types of ions. The interaction a of key divalent key ions, Ca2+, Mg2+, and (SO4)2-, on the carbonate rock surface are observed with relatively weak reactivity of Ca2+ compare to the other two. At the reservoir temperature, 90°C, the reactivity of Mg2+ with the carbonate rock is greater than that of Ca2+. The reactivity of multivalent anion (SO4)2- is also significant with carbonate rock surface, but it will induce surprising behavior on NMR response. The fundamental understandings acquired by the current study, effects of key ions in carbonate rock with single-phase fluid will be one of the key building blocks to develop rigid understanding of more complicated multi-phase fluid interaction with various types of reservoir rocks, and eventually draw conclusions on how these ions change rock wettability.
Scale up of Reactive Processes in Heterogeneous Media - Numerical Experiments and Semi-Analytical Modeling
Authors: Singh Harpreet , Srinivasan Sanjay 
Published: June 2014

Abstract
Performance prediction of reactive processes such as those associated with injection of chemicals that react with rock and fluids require accurate models for the processes. Frequently, these processes are studied at laboratory scale and modeling them at the field scale entails scaling-up of laboratory observations taking into account the spatial variability of parameters. The current practice is to perform spatial averaging of attributes and account for residual variability by calibration and history matching. This results in poor predictions of future reservoir performance. In this paper we scale-up such reactive transport processes considering both the spatial and temporal characteristics of these processes.
The first part of the paper investigates spatiotemporal scale-up of dispersivity accounting for field heterogeneity and reactivity of CO2. In this case, we investigate scale up by performing numerical simulations. Transport processes in reservoir models at three different length scales are simulated assuming homogeneous and heterogeneous permeability models. The variation in dispersivity with spatiotemporal scale is plotted and various conclusions are deduced regarding the impact of the permeability and conservative/reactive transport on the scale up characteristics of disersivity and mixing zone length. In the second part of the paper, a semi-analytical model for spatiotemporal covariance describing the reaction-dispersion process is used to derive the Representative Elementary Volume (REV) of concentration in combined space and time. The spatiotemporal covariance is used to compute the variance of mean concentration and REV is defined as the space-time scale over which the stabilization of this variance is achieved.
Key results of this work are that the scaling characteristics of dispersivity distinctly differ for low permeability and high permeability media. Heterogeneous media with spatial arrangements of both high and low permeability regions exhibit scaling characteristics of both high and low permeability media. Another important result is that reactions affect scaling characteristics of dispersivity in heterogeneous media. The semi-analytical models for scale-up of reaction-dispersion processes indicate that purely spatial or temporal investigation does not produce accurate estimate of REV. However, when scaling is investigated in a spatiotemporal setting, then the REV can be defined fairly accurately.
These results can be important for designing laboratory experiments and to predict scaled-up field response. Additionally, results also demonstrate that spatiotemporal numerical discretization of recovery processes for representing them in numerical flow simulations should be done appropriately based on the combined spatiotemporal REV scale of the process.
Experimental and Numerical Assessment of Chemical EOR in Oil-Wet Naturally-Fractured Reservoirs
Authors: Bourbiaux Bernard , Fourno André , Nguyen Quang-Long , Norrant Françoise , Robin Michel , Rosenberg Elisabeth , Argillier Jean-François 
Published: June 2014

Abstract
Among various ways to extend the lifetime of mature fields, chemical EOR processes have been subject of renewed interest in the recent years. Oil-wet fractured reservoirs represent a real challenge for chemical EOR as the matrix medium does not spontaneously imbibe the aqueous solvent of chemical additives. However, a wide variety of surfactants can now be considered for EOR, among which products that alter the matrix wettability. The present paper deals with that recovery strategy and compares it with other strategies based on viscous drive enhancement. Comparison is based on the physical and numerical interpretation of original representative experiments.
The kinetics of spontaneous imbibition of chemical solutions in oil-wet limestone plugs and mini-plugs has been quantified thanks to X-ray CT-scanning and NMR measurements. Despite the small size of samples and the slowness of experiments, accurate recovery curves could be inferred from in-situ fluid saturation measurements. Scale effects were found quite consistent between mini-plugs and plugs. During a second experimental step, representative drive conditions of a fractured reservoir were imposed between the end-faces of a plug, in order to account for the possibly-significant contribution of fracture viscous drive to matrix oil recovery.
These experiments were carefully analyzed and their numerical modeling was initiated with a simulation software that takes into account the multiple effects of surfactant presence on rock-fluids systems, including rock wettability modification and water-oil interfacial tension reduction. Model capability to reproduce experimental results is quite satisfactory provided that the evolution of capillary pressures in the presence of additives is sufficiently characterized. A few sensitivity studies underline also the necessity of disposing of a completely-documented physico-chemical data set to minimize modeling uncertainties in view of reliable recovery kinetics optimization.
In summary, the present paper provides an original quantitative description of chemical EOR process in neutral to oil-wet fractured reservoirs. This work calls for further development in order to specify the conditions on chemical additives and recovery process implementation that satisfy economic viability.
Diffusion and Matrix-Fracture Interactions during Gas Injection in Fractured Reservoirs
Authors: Shojaei Hasan , Jessen Kristian 
Published: June 2014

Abstract
Molecular diffusion can play a significant role in oil recovery during gas injection in fractured reservoirs. Diffusion of gas components from a fracture into the matrix extracts oil components from matrix and delays, to some extent, the gas breakthrough. This in turn increases both sweep and displacement efficiencies.
In current simulation models, molecular diffusion is commonly modeled using a classical Fick's law approach with constant diffusion coefficients. In the classical Fick's law approach, the dragging effects (off-diagonal diffusion coefficients) are neglected. In addition, the gas-oil diffusion at the fracture-matrix interface is normally modeled by assuming an average composition at the interface which does not have a sound physical basis.
In this paper, we present a dual-porosity model in which the generalized Fick's law is used for molecular diffusion to account for the dragging effects; and gas-oil diffusion at the fracture-matrix interface is modeled based on film theory in which the gas in fracture and oil in the matrix are assumed to be at equilibrium. A novel shape factor is also introduced for gas-oil diffusion based on film theory. Diffusion coefficients are calculated using the Maxwell-Stefan model and are pressure, temperature and composition dependent. A time-dependent transfer function is used for matrix-fracture exchange in which the shape factor is adjusted using a boost factor to differentiate between the transfer rate at early and late times.
Field-scale examples are used to demonstrate that the dragging effects (off-diagonal diffusion coefficients) can significantly impact the oil recovery during gas injection in fractured reservoirs. It is also shown that using proper physical models for matrix-fracture interactions (film theory for gas-oil diffusion and transfer function with boost factor) can considerably affect the simulation results as compared to conventional models. We also show that miscibility is not developed in the matrix blocks even at pressures above minimum miscibility pressure (MMP) when molecular diffusion is the main recovery mechanism during gas injection in fractured reservoirs.
The work presented in this paper is directly applicable to the study and design of gas injection processes in fractured reservoirs through an improved understanding of the effect of diffusion and matrix-fracture interactions on these processes.
CO2 Foam Pilot in Salt Creek Field, Natrona County, WY: Phase I: Laboratory Work, Reservoir Simulation, and Initial Design
Authors: Mukherjee J. , Norris S. O. , Nguyen Q. P. , Scherlin J. M. , Vanderwal P. G. , Abbas S. 
Published: June 2014

Abstract
In this paper we describe the design of a CO2 foam pilot in the Salt Creek Light Oil Unit in Natrona County, WY. CO2 foam technology was chosen as a promising candidate to improve sweep efficiency in certain target patterns. The second Wall Creek (WC2) sandstone formation is the primary producing interval, with a net thickness of about 80 feet and at a depth of approximately 2,200 feet. The first screening step towards identifying a pilot area involved a detailed study of the geologic features, injection-production characteristics, and operational aspects of numerous patterns in the field. An injector centered five-spot pattern was selected for the pilot. A surfactant formulation was developed that provided the desired foam response at reservoir conditions, and also met preliminary economic and operational expectations. The foam characteristics of the surfactant were further investigated by performing core-flood experiments. A history matched reservoir simulation model was developed to forecast the performance of the field in the absence of foam and thus provide a baseline to compare with the anticipated foam response. The model was later calibrated with foam performance data and used to guide the implementation of the pilot and to forecast field performance. The pilot was initiated in September 2013. Initial results are discussed.
Methane Production from Natural Gas Hydrates by CO2 Replacement – Review of Lab Experiments and Field Trial
Authors: Hauge L. P. , Birkedal K. A. , Ersland G. , Graue A. 
Published: June 2014

Abstract
Natural gas hydrate is a crystallized ice-like substance, consisting of water and natural gas, with methane as the most common gas. Water molecules form cages through hydrogen bonding and encapsulate gas molecules. Natural gas hydrates are found in the earth under high pressure and low temperature where water and gas co-exist, typically in permafrost and sub- marine environments. Hydrates have been considered a nuisance in the petroleum industry, creating barriers in pipe lines, and effort has mainly been put into preventing hydrate formation. However, natural gas hydrates are in recent decades acknowledged as a potential energy resource for the future; even conservative estimates suggest 1015 m3 CH4 STP present within hydrate.
Several methane production scenarios are proposed: thermal-, chemical- and pressure reduction induced dissociation is available, although depressurization is considered the least costly option. The University of Bergen has since 2002 worked on a fourth alternative: exchange of CH4 molecules with CO2. Lab scale experiments have repeatedly shown CO2-CH4 exchange within sediments. These experiments led to a field trial test in Alaska, operated by ConocoPhillips, by utilizing CO2 injection as a production method. Similar procedures as in the field test were performed in the lab, creating repetitive data for analysis on lab scale. This paper reviews results from both the laboratory and field pilot and discusses challenges and mitigating measures related to production.