bluuebunny/crossref_metadata_2025 huggingface dataset:
Assessment of CO2-Soluble Surfactants for Mobility Reduction using Mobility Measurements and CT Imaging
Authors: McLendon W. J. , Koronaios P. , McNulty S. , Enick R. M. , Biesmans G. , Miller A. , Salazar L. , Soong Y. , Romanov V. , Crandall D.
Published: April 2012

The addition of CO2-soluble, brine-soluble, surfactants to the high pressure CO2 may facilitate the in-situ generation of CO2-in-brine foams for conformance and/or mobility control. Most of these non-ionic surfactants dissolve in CO2 to concentrations of roughly 0.05–0.10wt% at CO2 EOR conditions and stabilize CO2-in-brine foams in high pressure windowed cells. Huntsman SURFONIC® N series surfactants, branched nonylphenol ethoxylates, containing an average of 12 (N-120) or 15 (N-150) ethylene oxide repeat units were selected for mobility and CT studies detailed in this paper.

Transient mobility measurements were conducted using a water-wet Berea core (104 mD), a water-wet Bentheimer sandstone core (∼1500 mD), and several mixed wettability SACROC carbonate cores (3.6 and 8.9 mD). The CO2 was injected into a brine-saturated core at a superficial velocity of 10 ft/day, and the surfactant was either not used, dissolved only in the brine at 0.06wt%, dissolved only in the CO2 at 0.06wt%, or dissolved in both the brine and the CO2 at 0.06wt. Regardless of what phase the surfactant was dissolved in, in-situ foam generation in the relatively high permeability sandstone was evidenced by total pressure drop values that were 2–3 times greater than the test with no surfactant. The mobility reduction was more modest (20–50% increases in pressure drop) in the lower permeability SACROC cores (3.6 and 8.9 mD) when the surfactant was dissolved in the CO2. When the surfactant was dissolved in the brine, the pressure drops increased by a factor of 1.5–3 for the 8.9 mD core.

CT scanning of in-situ foam generation was then conducted by injecting high pressure CO2 into a 5wt% KI brine-saturated water-wet Berea sandstone (3–8 mD). Tests were done with no surfactant or with the surfactant dissolved either in the brine at 0.03wt% or in the CO2 at 0.06wt%. At a low and high superficial velocity values of 0.47 ft/day and 4.7 ft/day, in-situ foam generation occurred when surfactant was dissolved in the brine or the CO2, but the core was swept more effectively by the foam generated with the surfactant present in the brine.
Surfactant Optimization for EOR Using Advanced Chemical Computational Methods
Authors: Buijse Marten , Tandon Kunj , Jain Shekhar , Handgraaf Jan-Willem , Fraaije Johannes G.
Published: April 2012

Surfactant EOR is an attractive method to recover the residual oil left behind in the reservoir after water flooding. The formulation of an effective surfactant system is a relatively complex and often time consuming process because the surfactant activity depends on the crude oil composition and the surfactant system must therefore be tailored to the oil. In practice many surfactant (and solvent) combinations need to be tested in the laboratory to optimize the performance.

An alternative approach, which is the focus in this paper, is to start with the molecular structure of surfactant and oil and apply Molecular Modeling techniques to optimize the surfactant system. The dissipative particle dynamics (DPD) method, used in the simulations discussed in this paper is a relatively new coarse-grained (meso-scale) method especially suited to study phase behavior in multiple phase systems such as surfactant/oil/brine. The paper will discuss the basic DPD features and results of DPD calculations of surfactants at the oil/brine interface.

To simulate the microemulsion structure on molecular level it is necessary to have a physical model of the surfactant interfacial film. The first part of the paper will review the relevant microemulsion physics, in particular the bending properties of the interfacial film that determine the magnitude of the (experimentally observed) interfacial tension.

To efficiently calculate microemulsion properties such as optimum salinity, a new method, called Method of Moments, was developed and implemented on DPD level. In this method a section of the surfactant/oil/brine interface is simulated to calculate the (lateral) stress profile and its moments. Computationally the method is relatively fast and it is flexible and can handle mixtures of surfactants/solvents, complex oils, etc. Results of calculations will be discussed in the paper.
Four-Phase Equilibrium Calculations of CO2/Hydrocarbon/Water Systems Using a Reduced Method
Authors: Mohebbinia Saeedeh , Sepehrnoori Kamy , Johns Russell T.
Published: April 2012

Three hydrocarbon phases can co-exist at equilibrium at relatively low temperatures in many CO2 floods. Formation of an aqueous phase in contact with hydrocarbon phases is inevitable in almost all recovery processes, because of the permanent presence of water in the reservoirs either as injection fluid or as initial formation water. Successful modeling of CO2 flooding requires accounting for the presence of four phases. However, as the number of phases increase, flash calculations become more difficult and time-consuming. A possible approach to reduce the computational time of the phase equilibrium calculations is to use reduced methods. This paper presents a general strategy to model the behavior of CO2/hydrocarbon/water systems where four equilibrium phases occur using a reduced flash approach. The speedup obtained by a reduced flash algorithm compared to the conventional flash approach is demonstrated for a different number of components and phases. The results show a significant speedup in the Jacobian matrix construction and in Newton-Raphson iterations using the reduced method when four phases are present. The computational advantage of the reduced method increases rapidly with the number of phases and components. The developed four-phase reduced flash algorithm is used to investigate the effect of introducing water on the phase behavior of two West Texas oil/CO2 mixtures. The results show significant changes in the phase splits and saturation pressures by adding water to these CO2/hydrocarbon systems.
Ethoxylated Cationic Surfactants for CO2 EOR in High Temperature, High Salinity Reservoirs
Authors: Chen Yunshen , Elhag Amro S. , Poon Benjamin M. , Cui Leyu , Ma Kun , Liao Sonia Y. , Omar Amr , Worthen Andrew J. , Hirasaki George J. , Nguyen Quoc P. , Johnston Keith P.
Published: April 2012

Despite significant interest in CO2 foams for EOR, very few studies have reported stable foams at high temperatures and high salinities, which are often encountered in the Middle East and elsewhere. Stable CO2/water (C/W) foams at high temperatures up to 120 °C and salinities have been achieved with ethoxylated cationic surfactants. The surfactants were shown to stabilize C/W foams with high salinity brine with NaCl concentration up to 182 g/L at 120 °C, 3400 psia, and to form unstable dodecane/water emulsions with the 120 g/L NaCl brine solutions. Thus, the foams have the potential to provide mobility control to prevent loses of CO2 in high permeability regions, but simultaneously allow high permeability in the presence of residual oil. The surfactants are soluble in CO2 and thus may be injected in the CO2 phase to simplify the EOR process. The aqueous solubility of the surfactant at high temperatures is enhanced with the appropriate number of EO groups on the amine head group. Viscosities of high-pressure C/W foams (emulsions) formed with these surfactants were investigated by capillary rheology. These hybrid cationic/nonionic surfactants combine the high cloud points of ionic surfactants with high solubilities in CO2 of nonionic surfactants. Furthermore, the variation of the tail length and the degree of ethoxylation offer great flexibility for stabilizing CO2 foams for EOR at high temperatures and high salinities. Ethoxylated cocoamine exhibited lower adsorption on calcite than that on dolomite, given the presence of silica sites in the latter. High divalent ion concentrations in 22% total dissolved solids (TDS) brine contributed to the reduction of surfactant adsorption on silica sites in the dolomite powder.
Generation of Nanoparticle-Stabilized Emulsions in Fractures
Authors: Roberts M. R. , Aminzadeh B. , DiCarlo D. A. , Bryant S. L. , Huh C.
Published: April 2012

We investigated the ability of a dispersion of specially surface-treated nanoparticles to stabilize an oil/water emulsion of prescribed internal structure created by flow within a fracture. We hypothesize that for a set of conditions (nanoparticle concentration, salinity, aqueous to organic phase ratio) a critical shear rate exists. That is, for flow rates that exceed this critical shear rate, an emulsion can be created.

Flow experiments were conducted within fractured cylinders of Boise sandstone and of Class H cement. The Boise sandstone core (D = 1 in and L = 12 in) was cut down its length and propped open to a specific aperture with beads. The fracture was saturated with dodecane which was displaced with nanoparticle dispersion, and vice versa while pressure drop across the fracture was recorded. Class H cement cylinders (D = 1 in and L = 3 in) were allowed to set, then failed in tension to create a rough-walled fracture along their length. These fractured cement cylinders were then sealed and encased in epoxy to isolate the fractures. CT scans of the encased fractures were used to determine the aperture width, which is utilized when calculating the shear rate inside of the fracture maintained during an experiment. A dispersion of surface-modified silica nanoparticles and decane were co-injected into both the Boise sandstone and cement fractures and the pressure drop was measured across the fractures at a variety of shear rates. The effluent of each experiment was collected in sample tubes.

Observation of the effluent and pressure drop data both support our hypothesis of emulsion generation being possible once a critical shear rate has been reached. Alteration of the injected phase ratio and increased residence time of the two phases inside of a fracture both affect the amount of emulsification occurring within the fractures. Increasing the residence time of both phases within a fracture allows for more opportunities for emulsification to occur, resulting in a greater amount of emulsion to be generated. Injection of high or low volumetric ratios of nanoparticle dispersion to organic phase results in little amounts of emulsion generation; however, between the nanoparticle dispersion to organic phase ratios of 0.25:1 and 2:1 significant amounts of emulsion are generated once a critical shear rate has been reached.
Measurement and Analysis of Surfactant Retention
Authors: Solairaj Sriram , Britton Christopher , Kim Do Hoon , Weerasooriya Upali , Pope Gary A.
Published: April 2012

Surfactant retention is one of the most important variables affecting the economics of chemical flooding and varies widely depending on the surfactant structure, mineralogy, salinity, pH, Eh, microemulsion viscosity, crude oil, co-solvent and mobility control among other variables. We have done a large number of dynamic surfactant retention measurements over a wide range of conditions using a variety of new-generation surfactants to recover crude oils from both sandstone and carbonate cores. Surfactant retention values for both surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) floods were measured and correlated with pH, total acid number (TAN) of the oil, temperature, co-solvent concentration, salinity of the polymer drive, mobility ratio, and molecular weight of the surfactant. Surfactant retention values ranged from about 0.01 to 0.37 mg/g of rock. SP and ASP formulations included mixtures of anionic and nonionic surfactants with and without co-solvents. The retention of anionic surfactants of all types was found to be similar on both sandstones and carbonate rocks.
Effect of Spontaneous Formation of Nanoparticle Stabilized Emulsion on the Stability of a Displacement
Authors: Aminzadeh B. , DiCarlo D. A. , Roberts M. , Chung D. H. , Bryant S. L. , Huh C.
Published: April 2012

Injecting nanoparticles into the subsurface can have a potential impact on altering both oil recovery and/or CO2 sequestration. In this work we conduct core floods in which a CO2-analogue fluid (n-octane) displaces brine with and without dispersed nanoparticles. We find that the floods with nanoparticles cause a greater pressure drop, and a change in flow pattern compared to the floods without. Emulsion formation is inferred by measuring the saturation distribution and pressure drop along the core. The results suggest that nanoparticle stabilized emulsion is formed during a drainage process (at low shear rate condition) which acts to reduce the mobility of the injected fluid.

We also perform imbibition experiments, where the nanoparticle dispersion in brine displaces n-octane. Here we observe little difference in the flow pattern and pressure drop as a function of nanoparticle concentration. There is an observed accumulation of nanoparticles at the imbibition front, which suggests that nanoparticles may be used as a tracer of the displacement front.
Improved Oil Recovery by Chemical Flood from High Salinity Reservoirs
Authors: Shiau B. J. , Hsu Tzu-Ping , Wan Wei , Lin Zhixun , Roberts Bruce L. , Harwell Jeffrey H.
Published: April 2012

Reservoirs containing very high total dissolved solids and high hardness make the design of a surfactant polymer (SP) flood extremely difficult because surfactant tends to precipitate and separate under these conditions. Beside divalent ions, Ca2+, Mg2+, presence of iron in the brine can be a challenging issue. Different surfactant formulations are evaluated and incorporate cosurfactants and co-solvents which minimize viscous macroemulsions, promote rapid coalescence under Winsor Type III conditions, and stabilize the chemical solution by reducing precipitation and phase separation. The optimal surfactant formulations were further evaluated in one-dimensional sand packs and coreflood tests using Berea sandstone, reservoir oils, and brines at reservoir temperatures. Using similar injection protocols, 0.5 pore volumes of surfactant/polymer + 0.5 pore volumes of polymer drive, experimental results show the oil recovery ranging from 46 % to 89% of the residual oil (Sor) after water flooding. The level of surfactant loading is less than 0.5 wt%. A single-well test was conducted to confirm laboratory results in situ in the presence of high-salinity formation water containing 185,000 mg/L total dissolved solids (TDS). The test is considered to be a technical success and confirms the effectiveness of the high-salinity surfactant-polymer formulation (0.4 wt% of surfactant and 1,800 ppm of polymer loading). The Sor was reduced from 25% to 7% resulting in approximately 72 % of the residual oil being mobilized. A pilot test at the same reservoir is scheduled to be performed in 2012 to further evaluate the effectiveness of surfactant formulation and address technical issues related to scale-up.
New Correlation to Predict the Optimum Surfactant Structure for EOR
Authors: Solairaj Sriram , Britton Christopher , Lu Jun , Kim Do Hoon , Weerasooriya Upali , Pope Gary A.
Published: April 2012

It is well known that the oil recovery efficiency of chemical EOR depends on microemulsion phase behavior and interfacial tension (IFT). The surfactants needed to obtain good phase behavior and ultra-low IFT vary greatly with oil characteristics and reservoir conditions. Hence, it is often necessary to test many surfactant formulations before finding a highly effective one. Based on both sound principles and extensive experience, one would expect to find a relationship between the optimum surfactant structure, the oil characteristics, the brine, and the temperature. Salager's equation (Salager et al., 1979, Anton et al., 2008) shows it is possible to correlate some of these variables to classical surfactant structure. We now have many new surfactants with widely different structures and many more good formulations with a wider range of oils, temperature and so forth. Thus, it becomes imperative to study the underlying trend and to identify the most important variables affecting the optimum surfactant structure. A new correlation has been developed using an extensive data set taking into account the effect of propylene oxide number (PON), ethylene oxide number (EON), temperature, brine salinity and the equivalent alkane carbon number (EACN) of the oil. The new correlation will help in identifying the most important variables and also to improve our understanding of the relationship among variables affecting optimum surfactant structure. In particular, the new equation can be used to predict the optimum carbon number of the surfactant hydrophobe. Results show that larger hydrophobes are needed as either the temperature or the equivalent alkane carbon number (EACN) of the oil increases. The surfactant formulations used for this study include mixtures of sulfate, sulfonate, carboxylate and non-ionic surfactants. This is a new and highly significant advance in the optimization of chemical EOR processes that will greatly reduce the time and cost of the effort required to develop a good formulation as well as to improve its performance.
Alkaline Surfactant Polymer Flooding using a Novel Class of Large Hydrophobe Surfactants
Authors: Liyanage Pathma J. , Solairaj Sriram , Arachchilage Gayani W , Linnemeyer Harold C , Kim Do Hoon , Weerasooriya Upali , Pope Gary A.
Published: April 2012

With recent advances in Alkaline-Surfactant-Polymer (ASP) flooding, the demand for high performance EOR surfactants is rapidly increasing. This is accompanied by the need for a diverse raw material base. We have successfully developed and tested a novel class of hydrophobes for anionic surfactants that satisfy this need at low cost. The hydrophobe for these novel surfactants is Tristyrylphenol (TSP), which is based on the petrochemical feed stocks, phenol and styrene. TSP based surfactants have unique structural features that can be exploited to fit many EOR surfactant needs. We illustrate the performance of this class of TSP surfactants for a waxy crude oil with a high acid number. Selecting a formulation proved difficult due to the high molecular weight of the crude. The TSP surfactant has four benzene rings that enhanced the solubility of the heavy components of the crude oil, including asphaltenes, making it an attractive choice. The dead crude oil was diluted with either decalin or cyclohexane to match the equivalent alkane carbon number (EACN) of the live crude oil. The TSP alkoxy sulfate molecules with varying lengths of propoxy (PO) and ethoxy (EO) chains were tested in microemulsion phase behavior experiments in order to obtain ultra-low IFT at optimum salinity with low microemulsion viscosities. The ASP formulation was successfully tested in reservoir core floods using both surrogate oil and live oil.
The Science of Membrane Technology to Further Enhance Oil Recovery
Authors: Henthorne Lisa , Wodehouse Jim
Published: April 2012

There are various membrane technologies available in the marketplace today to tailor water quality to the specific needs of an enhanced oil recovery (EOR) operation. Membrane technology has been proven and used offshore in the sulphate removal process (SRP) since DOW Filmtec and Marathon first introduced the membrane system in 1991. By the end of 2008, SRP systems were installed on over 44 offshore production facilities around the world.

The changing needs of the oil and gas industry are dictating the development of new technologies and the application of proven technology in novel ways to meet the industry demand. These new applications and technologies have the potential to impact production on a global scale. For instance, optimizing water chemistries throughout a CEOR flood by carefully choosing membrane and polishing technologies can favorably change CEOR project economics and therefore further enhance oil recovery by expanding the number of reservoirs globally in which CEOR is economically attractive.

This paper will discuss what can be achieved with today's technology and the results from recent pilot testing of RO technology adapted from brackish water applications to be used to selectively remove ions for seawater-based EOR applications.
Nanoparticle Stabilized Carbon Dioxide in Water Foams for Enhanced Oil Recovery
Authors: Worthen Andrew J. , Bagaria Hitesh G. , Chen Yunshen , Bryant Steven L. , Huh Chun , Johnston Keith P.
Published: April 2012

Viscous C/W foams were generated without the use of polymers or surfactants by shearing CO2 and an aqueous phase containing partially hydrophobic silica nanoparticles in a beadpack filled with 180μm glass beads. Silica particles with 50% SiOH coverage were chosen because they have a hydrophilicity that falls between the 42% SiOH optimum foaming ability for A/W foams (Binks and Horozov 2005) and the 67% SiOH which gave maximum O/W emulsion stability (Binks and Lumsdon 2000). These 50% SiOH silica nanoparticles were found to be interfacially active for CO2-water systems, and stabilized the desired curvature of C/W foams. When the HCB of the nanoparticles is tuned to give contact angles less than 90°, the particles reside primarily in the water phase and C/W foams can be formed. Formation of C/W emulsions stabilized solely with nanoparticles is desirable because it does not require solvation of surfactant tails or polymer chains by CO2. Interfacially active nanoparticles can adsorb at the CO2 water interface without the need for solvation in CO2.

Properly designed nanoparticles generated foams that were more stable than foams generated with polymer-coated nanoparticles or with the nonionic surfactant Tergitol™ 15-S-20 alone. Macroscopic observations showed foams generated solely with 50% SiOH nanoparticles stayed bright white and opaque over 23 hours, while foams generated with PEG-coated silica particles or with surfactant alone resolved nearly completely. Foams generated solely with Tergitol™ 15-S-20 were unstable because surfactant molecules dynamically enter and leave the interface and thus do not provide long-term stabilization. Foams generated with PEG-coated silica particles, though initially very viscous, showed poor long-term stability because of the small particle size and poor solvation of PEG chains in CO2. The larger 50% SiOH nanoparticles strongly adsorbed at the CO2-water interface and provided a barrier around the CO2 bubbles, resulting in very stable foams.
Three-Phase Flow during Steam Chamber Rise
Authors: Murtaza Muhammad , Dehghanpour Hassan
Published: April 2012

During Steam Assisted Gravity Drainage (SAGD) process, a steam chamber is formed due to continous steam injection. This steam chamber first moves upward to the top of the reservoir and then spreads side ways. The upward displacement of the steam chamber is the key parameter, for determining the optimum rate of steam injection. Slow injection rate will give low oil recovery where as high injection rate will cause steam loss. Furthermore, the cost of steam is more than half of the total cost of the project. Therefore it is necessary to determine the accurate rate of steam chamber rise to make the process economic.

Recent experiments show that oil flow is coupled to water flow during three-phase gravity drainage in water-wet system. In this paper, we argue that this type of flow coupling can be significant during SAGD. We extend Butler (1987) analytic model for the rise of interfering steam chambers to account for three phase flow and flow coupling.

We also show the significance of flow coupling by solving a simple numerical example. We observe that by including three-phase drainage and the coupling flow in the steam chamber, the vertical rise velocity of steam chamber increases. Moreover the steam chamber rise velocity is sensitive to viscosity-temperature characterstics (m) of oil. As the value of m decreases the rise velocity increases. Furthermore, we compre the model predictions with measured values from five fields, and one experiment.
2-D Visualisation of Unstable Waterflood and Polymer Flood for Displacement of Heavy Oil
Authors: Skauge Arne , Ormehaug Per Arne , Gurholt Tiril , Vik Bartek , Bondino Igor , Hamon Gerald
Published: April 2012

Waterflooding and polymer assisted waterflood in heavy oil reservoirs has currently gaining great attention. Enhanced water injection schemes represent an alternative in cases where thermal methods are either impractical or uneconomic. This study describes and analyses the oil mobilization by imaging the oil displacement at adverse mobility by injection of brine and polymer. The objectives were to improve description of viscous instabilities, mechanisms for finger growth, water channeling at adverse mobility ratio, and oil mobilization by polymers.

Experiments have been made on 2D (30cmx30cm Bentheimer slabs) studying waterflooding and tertiary polymer injection in extra heavy oils (2000cp and 7000cp). The sandstone represents a relatively homogeneous and high permeability porous medium. The experiments utilize gamma and X-ray source for porosity and saturation measurements, and an X-ray imaging system to visualize displacements and thereby quantify the underlying flow mechanisms and oil recovery.

At water wet condition capillary smears the front and prevents viscous fingers even at high adverse viscosity ratio. Changes in wettability (aging the rock material) dampen the capillarity and fingers then become more pronounced. High microscopic recovery to waterfloods (up to 30% after 5 PV injected) were achieved, and most importantly a rather impressive further gain in oil recovery after polymer flooding reaching final recoveries of more than 60%. The waterflood creates multiple thin sharp fractal-like fingers that propagate in the Bentheimer sandstone material. The 2D X-ray imaging describes the finger formation, growth, and also the later water channels formed. Polymer injection gives a fast increase in oil production, and analysis from the imaging proves that the oil is mainly produced through the established water channels.

The 2-D experiments demonstrate the mechanisms of how heavy oil is mobilized by polymer injection. Saturation maps were accurately measured by means of X-ray scans and this enabled the visualization of flow instability, establishment of water channels and oil mobilization with high resolution.
Rheology and Transport of Improved EOR Polymers under Harsh Reservoir Conditions
Authors: Kulawardana Erandimala U. , Koh Heesong , Kim Do Hoon , Liyanage Pathma J. , Upamali Karasinghe A. , Huh Chun , Weerasooriya Upali , Pope Gary A.
Published: April 2012

New polymers that are stable in harsh environments (high salinity/hardness and high temperature) are in high demand because of the need for chemical EOR in oil reservoirs with these conditions. Commonly used partially hydrolyzed polyacrylamides (HPAM) have been successfully used in the field for decades, but they hydrolyze at high temperature and eventually precipitate in the presence of high concentrations of divalent cations. This paper mainly focuses on rheology and transport behavior of scleroglucan (non-ionic polysaccharide) and N-vinylpyrrolidone (NVP)-polyacrylamide (AM) co-polymer. The rigid, rod-like, triple helical structure of scleroglucan imparts exceptional stability and its non-ionic functionality makes it insensitivity to salinity and hardness. By a different mechanism, NVP in modified HPAM protects the polymer's amide group against thermal hydrolysis, i.e., by sterically hindering the amide group. This allows maintaining high viscosity even in high salinity brines at high temperature. Both scleroglucan and NVP co- or ter-polymers show good filterability and transport properties in sandstone and carbonate cores at high temperature and in brine with high salinity and hardness. Therefore, both polymers are promising candidates for polymer flooding, surfactant-polymer flooding and alkali-surfactant-polymer flooding in hard brine at high temperature, but must be evaluated under specific reservoir conditions.
Potential for In Situ Combustion in Depleted Conventional Oil Reservoirs
Authors: Moore R. G. , Mehta S. A. , Ursenbach M. G. , Gutiérrez D.
Published: April 2012

In oil producing regions like the US Mid-Continent, there are a large number of mature conventional oil fields that have reached or are approaching their production limit by conventional techniques, however, current strong oil prices and security issues justify additional EOR/IOR efforts. Air injection-based techniques (fireflooding or in situ combustion) have been demonstrated to provide commercially successful recovery from medium and light oils reservoirs. While the history of air injection-based EOR is littered with the perception of failed projects, many of the failures were associated with low oil prices. In other cases, failures were due to compressor problems, or incorrect concepts of how air injection processes operate. Ineffective ignitions, failure to inject enough air, and applications in reservoirs that had no hope of success explain the trouble with many past projects.

This paper reviews some of the successful air injection projects in higher gravity oil reservoirs and discusses the elements that are critical for success. These include the ability to ignite and continuously burn a fraction of the oil at reservoir conditions, the suitability of the reservoir for a gas-injection based recovery process, the availability and suitability of preexisting infrastructure, and a reasonable prediction of how much air should be injected and how much oil recovery could be expected. The paper also discusses possible options for taking advantage of the product gas stream.

The purpose of this paper is to arm the petroleum engineer with the relevant information and the right set of questions to ask when considering the application of air injection in a given field.
Experimental and Modeling Study of Multicontact Miscible Displacements
Authors: Shojaei Hasan , Rastegar Reza , Jessen Kristian
Published: April 2012

In order to estimate the potential incremental hydrocarbon recovery by CO2 injection, compositional reservoir simulators are commonly used in the industry. Successful design and implementation of CO2 injection processes rely in part on the accuracy by which the available simulation tools can represent the physics that govern the displacement behavior in a reservoir. In this paper, we investigate the accuracy of some physical models that are frequently used to describe dispersive mixing and mass transfer in compositional reservoir simulation.

We have designed a quaternary analog fluid system (alcohol-water-hydrocarbon) that mimics the phase behavior of CO2- hydrocarbon mixtures at high pressure and temperature. A porous medium was designed using PolyTetraFlouroEthylene (PTFE) materials to ensure that the analog oil acts as the wetting phase, and the properties of the porous medium were characterized in terms of porosity, permeability and dispersivity. Relative permeability and interfacial tension (IFT) measurements were also performed to delineate interactions between the fluid system and the porous medium.

The effluent concentrations from 2-component first-contact miscible displacement experiments exhibit a tailing behavior that is attributed to imperfect sweep of the porous medium: a feature that is not captured by normal dispersion models. To represent this behavior in displacement calculations, we use a dual-porosity model including mass transfer between flowing and stagnant porosities. Two 4-component two-phase displacement experiments were performed at multicontact miscible conditions and the effluent concentrations were interpreted by numerical calculations.

We demonstrate that the accuracy of our displacement calculations relative to the experimental observations is sensitive to the selected models for dispersive mixing, mass transfer between flowing and stagnant porosities, and IFT scaling of relative permeability functions. We also demonstrate that numerical calculations substantially agree with the experimental observations for some physical models with limited need for model parameter adjustment.

The work presented in this paper is directly applicable to the study and design of EOR/sequestration processes through an improved understanding of dispersive mixing and mass transfer in these processes.
Nanofluid System Improves Post Frac Oil and Gas Recovery in Hydrocarbon Rich Gas Reservoirs
Authors: Penny Glenn , Zelenev Andrei , Lett Nathan , Paktinat Javad , O’Neil Bill
Published: April 2012

The primary purpose of using surfactants in stimulating hydrocarbon rich gas reservoirs is to reduce interfacial tension, and/or modify contact angle and reservoir wettability. However, many surfactants either adsorb rapidly within the first few inches of the formation, or negatively impact reservoir wettability, thus reducing their effectiveness in lowering capillary pressure. These phenomena can result in phase trapping of the injected fluid adversely impacting oil and gas production.

This study describes experimental and field studies comparing various common surfactants used in oil bearing formations including alcohol ethoxylates, EO-PO block copolymers, ethoxylated amines and a multi-phase complex nano fluid system to determine their impact on oil recovery and adsorption tendencies when injected through 5-foot and 1 ft sand columns. Ammot cell tests were used to evaluate imbibition of oil and water and a core flow apparatus was used to evaluate regained relative permeabilities. The results are correlated with surface energies of actual formation materials, oils and treating fluids. The results are used to select formulations containing surfactant, solvents and co-solvents to apply within the fracturing fluid to decrease adsorption, eliminate post treatment emulsions and improve oil and gas recovery in hydrocarbon rich gas wells.
Double-Layer Expansion: Is It A Primary Mechanism of Improved Oil Recovery by Low-Salinity Waterflooding?
Authors: Nasralla Ramez A. , Nasr-El-Din Hisham A.
Published: April 2012

Several mechanisms which could contribute to improved oil recovery (IOR) by low-salinity waterflooding have been proposed. However, the main mechanism is still debated. Nasralla et al. (2011a) showed that low-salinity water has an impact on the electrical charges at oil/brine and rock/brine interfaces, and it causes expansion of the double layer, which is the main reason behind wettability alteration and high oil recovery. Nevertheless, double-layer expansion by low-salinity water might contribute, but not be the primary mechanism. Therefore, this paper investigates this mechanism and shows how it is involved in the process of IOR.

Electrical surface charge is a function of brine's pH, so the injected brine's pH was manipulated to show how oil recovery during low-salinity waterflooding depends on changes in electrical charges. Coreflood experiments were conducted using Berea sandstone cores 20 in. long; different brines (TDS varies from 0.5 to 55 kmg/l) were injected. Furthermore, zeta potential at rock/brine and oil/brine interfaces was measured for the brines used at different pHs. The contact angle technique was used to evaluate the alteration of rock wettability by the same brine at a different pH.

Zeta potential results showed that decreasing low-salinity brines’ pH makes the electrical charges at both oil/brine and brine/rock interfaces weakly negative, which reduces the repulsion forces between oil and rock, and as a result the rock becomes more oil-wet, which was confirmed by contact angle measurements. Moreover, coreflood experiments indicated that injecting low-salinity brine at lower pH recovered less amount of oil compared to the original pH because of the elimination of the low-salinity water effect on electrical charges. In conclusion, expansion of the double layer is a dominant mechanism of oil recovery improvement by low-salinity waterflooding.
Polymer Flooding a ~500-cp Oil
Authors: Moe Soe Let K. P. , Manichand R. N. , Seright R. S.
Published: April 2012

Relatively high oil prices, modest polymer prices, and advances that promote higher injectivity for polymer solutions have allowed polymer flooding to be applied in reservoirs with notably more viscous oils than in previous years. This paper describes a polymer flooding pilot project in the Tambaredjo field in Suriname. The average viscosity of the produced oil is ~1,700 cp, but solution gas reduces the effective oil viscosity in the reservoir to 400–600 cp (through the "foamy oil" mechanism). Interestingly, the primary drive mechanism in the pilot area is compaction—leading to ~20% OOIP recovery. Because various restrictions preclude application of thermal methods, polymer flooding was explored as a means to enhance oil recovery. The average permeability of the sand exceeds 4darcys, but the level of heterogeneity is significant (>10:1 permeability contrast is common). The first simulation efforts suggested that injection of 25–40-cp polymer solutions might be optimum, considering both displacement and injectivity. Consequently, ~40-cp polymer solutions were injected during the first part of the pilot. However, later analysis revealed that sweep efficiency could be improved significantly using polymer solutions up to 160 cp. Although injection was done at pressures below what was believed to be the formation parting pressure, injectivity data from several water injection cycles shows that partition of the formation followed by partial sustenance of the fracture did occur. Analysis of produced water salinities, polymer and tracer concentrations, water/oil ratios (WOR), and inter-well pressure responses all indicated that severe channeling (i.e., through fracture-like features) did not occur. Instead, analysis of the project response indicated that (1) sweep could benefit from injecting more viscous polymer solutions, (2) injectivity for more viscous polymers would not be a problem because of controlled (i.e., not detrimental) fracture extension, and (3) oil production rates could be enhanced (without sacrificing WOR) by increasing injection rates. Consequently, these ideas are currently being field tested in our project. This paper details results to date for this polymer pilot.
EDITORIAL - Extubation Algorithms: Why, where and when do we need them?
Authors: Whitener Stephanie , Schmidt Ulrich
Published: April 2012

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Biomechanical In Vitro - Stability Testing on Human Specimens of a Locking Plate System Against Conventional Screw Fixation of a Proximal First Metatarsal Lateral Displacement Osteotomy
Authors: Arnold Heino , Stukenborg-Colsman Christina , Hurschler Christof , Seehaus Frank , Bobrowitsch Evgenij , Waizy Hazibullah
Published: April 2012

Introduction:

The aim of this study was to examine resistance to angulation and displacement of the internal fixation of a proximal first metatarsal lateral displacement osteotomy, using a locking plate system compared with a conventional crossed screw fixation.

Materials and Methodology:

Seven anatomical human specimens were tested. Each specimen was tested with a locking screw plate as well as a crossed cancellous srew fixation. The statistical analysis was performed by the Friedman test. The level of significance was p = 0.05.

Results:

We found larger stability about all three axes of movement analyzed for the PLATE than the crossed screws osteosynthesis (CSO). The Friedman test showed statistical significance at a level of p = 0.05 for all groups and both translational and rotational movements.

Conclusion:

The results of our study confirm that the fixation of the lateral proximal first metatarsal displacement osteotomy with a locking plate fixation is a technically simple procedure of superior stability.
Relationship Between Brassiere Cup Size and Shoulder-Neck Pain in Women
Authors: Oo Myint , Wang Zhuo , Sakakibara Toshihiko , Kasai Yuichi
Published: April 2012

There are very few reports in regard to relationship between breast size and shoulder-neck pain. The purpose of this study is to examine the correlations among breast size, brassiere cup size, and moment-in-time reporting of shoulderneck pain in a group of adult women. Three hundred thirty nine female volunteers from the hospital staff answered the questionnaire. Breast size, brassiere cup size, and shoulder-neck pain were self-reported by each participant. The relationship among breast size, brassiere cup size and shoulder-neck pain was investigated. Spearman’s test showed no significant relationship between shoulder-neck pain and brassiere cup size. However, after participants were classified into two groups (small brassiere cup size and large brassiere cup size with 219 and 120 participants, respectively), there was a significant positive correlation between shoulder-neck pain and large brassiere cup size (p<0.05). There was no significant relationship between shoulder-neck pain and breast size. In conclusion, large brassiere cup size is an important cause of shoulder-neck pain.
Cryopreservation Effect on Proliferative and Chondrogenic Potential of Human Chondrocytes Isolated from Superficial and Deep Cartilage
Authors: Muiños-López Emma , Rendal-Vázquez Mª Esther , Hermida-Gómez Tamara , Fuentes-Boquete Isaac , Díaz-Prado Silvia , Blanco Francisco J
Published: April 2012

Objectives:

To compare the proliferative and chondrogenic potential of fresh and frozen chondrocytes isolated from superficial and deep articular cartilage biopsies.

Materials and Methodology:

The study included 12 samples of fresh and frozen healthy human knee articular cartilage. Cell proliferation was tested at 3, 6 and 9 days. Studies of mRNA quantification, protein expression and immunofluorescence for proliferation and chondrogenic markers were performed.

Results:

Stimulation of fresh and frozen chondrocytes from both superficial and deep cartilage with fetal bovine serum produced an increase in the proliferative capacity compared to the non-stimulated control group. In the stimulated fresh cells group, the proliferative capacity of cells from the deep biopsy was greater than that from cells from the superficial biopsy (0.046vs0.028, respectively, p<0.05). There was also a significant difference between the proliferative capacity of superficial zone fresh (0.028) and frozen (0.051) chondrocytes (p<0.05).CCND1mRNA and protein expression levels, and immunopositivity forKi67revealed a higher proliferative capacity for fresh articular chondrocytes from deep cartilage. Regarding the chondrogenic potential, stimulated fresh cells showed higherSOX9andCol IIexpression in chondrocytes from deep than from superficial zone (p<0.05,Tstudent test).

Conclusions:

The highest rate of cell proliferation and chondrogenic potential of fresh chondrocytes was found in cells obtained from deep cartilage biopsies, whereas there were no statistically significant differences in proliferative and chondrogenic capacity between biopsy origins with frozen chondrocytes. These results indicate that both origin and cryopreservation affect the proliferative and chondrogenic potential of chondrocytes.
Derivation and Validation of a Cytokine-Based Assay to Screen for Acute Rejection in Renal Transplant Recipients
Authors: De Serres Sacha A. , Mfarrej Bechara G. , Grafals Monica , Riella Leonardo V. , Magee Ciara N. , Yeung Melissa Y. , Dyer Christine , Ahmad Usaila , Chandraker Anil , Najafian Nader
Published: April 2012

Background and objectives

Acute rejection remains a problem in renal transplantation. This study sought to determine the utility of a noninvasive cytokine assay in screening of acute rejection.

Design, setting, participants, & measurements

In this observational cross-sectional study, 64 patients from two centers were recruited upon admission for allograft biopsy to investigate acute graft dysfunction. Blood was collected before biopsy and assayed for a panel of 21 cytokines secreted by PBMCs. Patients were classified as acute rejectors or nonrejectors according to a classification rule derived from an initial set of 32 patients (training cohort) and subsequently validated in the remaining patients (validation cohort).

Results

Although six cytokines (IL-1β, IL-6, TNF-α, IL-4, GM-CSF, and monocyte chemoattractant protein-1) distinguished acute rejectors in the training cohort, logistic regression modeling identified a single cytokine, IL-6, as the best predictor. In the validation cohort, IL-6 was consistently the most accurate cytokine (area under the receiver-operating characteristic curve, 0.85; P=0.006), whereas the application of a prespecified cutoff level, as determined from the training cohort, resulted in a sensitivity and specificity of 92% and 63%, respectively. Secondary analyses revealed a strong association between IL-6 levels and acute rejection after multivariate adjustment for clinical characteristics (P<0.001).

Conclusions

In this pilot study, the measurement of a single cytokine can exclude acute rejection with a sensitivity of 92% in renal transplant recipients presenting with acute graft dysfunction. Prospective studies are needed to determine the utility of this simple assay, particularly for low-risk or remote patients.
An Investigation of Self-Assessment Bias in Mental Health Providers
Authors: Walfish Steven , McAlister Brian , O'Donnell Paul , Lambert Michael J.
Published: April 2012

Previous research has consistently found self-assessment bias (an overly positive assessment of personal performance) to be present in a wide variety of work situations. The present investigation extended this area of research with a multi-disciplinary sample of mental health professionals. Respondents were asked to: (a) compare their own overall clinical skills and performance to others in their profession, and (b) indicate the percentage of their clients who improved, remained the same, or deteriorated as a result of treatment with them. Results indicated that 25% of mental health professionals viewed their skill to be at the 90th percentile when compared to their peers, and none viewed themselves as below average. Further, when compared to the published literature, clinicians tended to overestimate their rates of client improvement and underestimate their rates of client deterioration. The implications of this self-assessment bias for improvement of psychotherapy outcomes are discussed.
Development of a Facebook Addiction Scale
Authors: Andreassen Cecilie Schou , Torsheim Torbjørn , Brunborg Geir Scott , Pallesen Ståle
Published: April 2012

The Bergen Facebook Addiction Scale (BFAS), initially a pool of 18 items, three reflecting each of the six core elements of addiction (salience, mood modification, tolerance, withdrawal, conflict, and relapse), was constructed and administered to 423 students together with several other standardized self-report scales (Addictive Tendencies Scale, Online Sociability Scale, Facebook Attitude Scale, NEO–FFI, BIS/BAS scales, and Sleep questions). That item within each of the six addiction elements with the highest corrected item-total correlation was retained in the final scale. The factor structure of the scale was good (RMSEA = .046, CFI = .99) and coefficient alpha was .83. The 3-week test-retest reliability coefficient was .82. The scores converged with scores for other scales of Facebook activity. Also, they were positively related to Neuroticism and Extraversion, and negatively related to Conscientiousness. High scores on the new scale were associated with delayed bedtimes and rising times.