bluuebunny/crossref_metadata_2025_split huggingface dataset:
Water Shut-off with Polymer Gels in A High Temperature Horizontal Gas Well: A Success Story
Authors: Al-Muntasheri Ghaithan A. , Sierra Leopoldo , Garzon Francisco , Lynn Jack D. , Izquierdo Guillermo 
Published: July 2010

AbstractA horizontal hot deep gas well was not on production due to high water cut. The well had a bottom hole temperature of 300°F (149°C) and a bottom hole pressure of 7,000 psi. The well was completed into a carbonate reservoir with an average permeability ranging from 2 to 3 mD. It was completed with a 7 in liner at a measured depth (MD) of 13,611 ft. The open-hole section extends from 13,611 to 16,456 ft. After the well completion operation, water was observed entering the open-hole section at the toe at a depth of 14, 677 ft. The exact water producing zone was identified by the resistivity log run on the subject well. Therefore, a mechanical packer was set in the open-hole section at 14,677 ft to isolate the water producing interval. The packer did not solve the problem. The water production continued to occur.Due to their versatility, polymer gels were considered for remediating this problem and to revive the well. A gel system based on a low molecular weight polymer crosslinked with an organic crosslinker was considered. A serious challenge was the high temperature of the reservoir. The high temperature conditions imposed the use of a retarder to elongate the onset gelation time during the polymer gel placement. The available mixing waters in this field contained significant amounts of salts (a total dissolved solids content of 1,188 ppm). These solids caused compatibility problems upon contact with the commercially available retarder. Therefore, a new retarder was developed. The retarder was cost-effective, efficient and compatible with the available saline mixing water. The retarder's placement was examined in porous media under conditions similar to those encountered in the field (55 minutes placement time). The gel did not show any injectivity problems indicating the efficient nature of the retarder. The initial recommended recipe of the gel showed syneresis due to the extra amount of the crosslinker suggested. This was addressed by reducing the crosslinker concentrations in the gel recipe.The treatment utilized a pre-flush to displace the reservoir fluids around the wellbore and to cool down the near wellbore area. This helped reduce the near wellbore area temperature from 300 to 240°F according to the temperature simulations. The gelant contained 250 gal/1000 gal of polymer with a 10 gal/1000 gal of crosslinker. After the gelant placement, the well was shut-in for three days. Once opened, the well showed an increase in gas production by a factor of 7.7 with a water cut reduction of 42 %.
Effects of Magnetic Field on the Motion of Multiphase Fluids Containing Paramagnetic Particles in Porous Media
Authors: Prodanovic Maša , Ryoo Seungyup , Rahmani Amir R. , Kuranov Roman , Kotsmar Csaba , Milner Thomas E. , Johnston Keith P. , Bryant Steven L. , Huh Chun 
Published: July 2010

Abstract
When paramagnetic nanoparticles are adsorbed at the oil-water interface or dispersed in one of the fluid phases in reservoir rock pores, then exposed to an external magnetic field, the resultant particle movements displace the interface. Interfacial tension acts as a restoring force, leading to interfacial fluctuation and a pressure (sound) wave. Here we focus on the interface motion. We apply the theory of ferrofluids to the case of an interface in a cylindrical pore. The predictions are consistent with experiments with an aqueous suspension of iron oxide nanorods in which the interface motion is measured by optical coherence tomography. The relative densities of the fluid phases (air/aqueous and dodecane/aqueous in our case) strongly affect the displacement of the interface. Application of a magnetic field introduces pressure-like terms into the equation of fluid phase motion. We then recast the problem in terms of interface motion, extending a numerical interface-tracking model based on the level-set method to account for capillarity and magnetic pressures simultaneously. We use the model to illustrate the motion of an interface between inviscid fluids at the pore scale when magnetic forces are imposed on one fluid phase.
Innovative Emergency Coiled-Tubing Disconnect System for Tender Barge Operations
Authors: Noguera J. A. , Hampson R. , Tran Q-B. 
Published: July 2010

Abstract
In the last few years, Indonesia has experienced a significant increase in offshore activities requiring support from tender barges. This type of operation has helped overcome most of the offshore well-intervention challenges, in terms of crane capabilities, space, load, etc. However, operating in high waves and strong currents has introduced other technical and safety challenges, especially when performing coiled-tubing (CT) operations.
In this kind of operation, the coiled-tubing reel and pumping spread are kept on the tender barge, while the injector head and well-control stack are set on the platform. The possibilities of losing the barge anchors or a catastrophic situation at the platform generated the need to develop a system to quickly disconnect the equipment on the barge from the platform by safely cutting the coiled tubing at the reel while minimizing the personnel exposure time to at-risk conditions, as well as avoiding the loss of treatment or hydraulic fluid to the environment. The new system was designed to be hydraulically capable of (1) releasing the injector and blowout-preventer (BOP) hoses while containing the hydraulic fluid, (2) holding the string reel end in place, and (3) cutting the string at the reel.
This paper will document the system components’ design processes, field testing, and field implementation.
Compositional Simulation of In-Situ Combustion EOR: A Study of Process Characteristics
Authors: Jain Priyanka , Stenby Erling H. , von Solms Nicolas 
Published: July 2010

ABSTRACT
In order to facilitate the study of the influence of reservoir process characteristics in In-Situ combustion modeling and advance the work of Kristensen et al. in the domain of thermal oil recovery methods; a fully compositional In-situ combustion (ISC) model of Virtual Kinetic Cell (VKC; single-cell model) for laboratory scale combustion simulation is used. Preceding research work primarily focused on a kinetic model that was based on six components and incorporated four chemical reactions. However, modeling of a thermal process as complex as In-situ combustion requires in-depth understanding of detailed reaction kinetics and multidisciplinary process data. This paper extends the understanding of previous research done in this domain by performing the process simulations to study further the impact of oxidation reactions and combustion reactions of crude oils along with their saturate, aromatic, resin, and asphaltene (SARA) fractions. This incorporates fourteen pseudo components and fourteen reactions (distributed amongst thermal cracking, low temperature oxidation and high temperature oxidation). The paper presents a set of derivative plots indicating that reservoir process characterization, in terms of thermal behavior of oil, can be well construed by thermo-oxidative sensitivity analysis of SARA fractions. It can be interpreted from the results that operating parameters like air injection rate, oxygen feed concentration and activation energy have significant influence on oil recovery; an increase in air injection rate can lead to cooling of the combustion front and thus decrease oil recovery, while increase in oxygen feed assists combustion and contributes towards improved oil recovery. The critical properties of the pseudo components are not determined experimentally, thus extending significance to fluid characterization. The composition plays a key role e.g. due to asphaltenes being most resistant toward oxidation and saturates being the easiest oxidizable ones.
Snorre Low Salinity Water Injection - Core Flooding Experiments and Single Well Field Pilot
Authors: Skrettingland K. , Holt T. , Tweheyo M. T. , Skjevrak I. 
Published: July 2010

Abstract
Low salinity water (lowsal) flooding has been evaluated for increased oil recovery at the Snorre field. Core flooding experiments and a single well chemical tracer test (SWCTT) field pilot have been performed to measure the remaining oil saturation after sea water and after lowsal flooding.
The laboratory core flooding experiments done at reservoir and low pressure conditions involved core material from the Upper and Lower Statfjord and Lunde formations. The core material from the Statfjord formations gave incremental recovery in the order of 2 % of original oil in place (OOIP) by injection of diluted sea water. Similar amounts were produced during following NaCl-based lowsal injections. The same trend was observed in the high and low pressure experiments. No significant response to lowsal flooding was observed for Lunde cores. No response was normally observed during alkaline injection.
The SWCTT field pilot test was carried out in the Upper Statfjord formation. The average oil saturations after sea water injection, after lowsal injection and after a new sea water injection were determined; showing no significant change in the remaining oil saturation. The measured in-situ value of remaining oil saturation after sea water flooding was in agreement with previous SCAL experiments.
The measured effect of tertiary lowsal flooding from core experiments was in agreement with the SWCTT. Both measurements indicated only low or no effect from lowsal injection.
It has been suggested that lowsal flooding has a potential for improved oil recovery in all clayey sandstone formations containing crude oil. The results from this work indicate that the initial wetting condition is a crucial property for the effect of lowsal injection.
Chemical Degradation of Polyacrylamide Polymers Under Alkaline Conditions
Authors: Levitt David B. , Pope Gary A. , Jouenne Stephane 
Published: July 2010

Abstract
Hydrolysis of polyacrylamide-based polymers is rapid and extensive under the alkaline conditions typical of alkaline-surfactant-polymer (ASP) flooding. Even at room temperature, significant hydrolysis occurs within one to two months in the presence of sodium carbonate. While this implies that polymers used in ASP floods will rapidly become susceptible to precipitation with divalent cations, in most cases the alkali present will be the most sensitive component to precipitation so this may be a moot point. Also, autoretarding kinetics under alkaline conditions limit hydrolysis at 100 °C whereas complete hydrolysis occurs under neutral conditions. Furthermore, in-situ hydrolysis of initially unhydrolyzed polyacrylamide is proposed as a promising strategy for ASP floods since the injectivity of the unhyrolyzed polyacrylamide will be greater than hydrolyzed polyacrylamide due to its lower initial viscosity. The lower initial viscosity is not a disadvantage since once it has been hydrolyzed in-situ, its viscosity will increase.
Nanoparticle-Stabilized Emulsions for Applications in Enhanced Oil Recovery
Authors: Zhang Tiantian , Davidson Andrew , Bryant Steven L. , Huh Chun 
Published: July 2010

Abstract
Nanoparticle-stabilized emulsions have attracted many researchers' attention in recent years due to many of their specific characteristics and advantages over conventional emulsions stabilized by surfactants or by colloidal particles. For example, the solid nanoparticles can be irreversibly attached to the oil-water interface and form a rigid nanoparticle monolayer on the droplet surfaces, which induce highly stable emulsions. Those emulsions can withstand harsh conditions. Compared to colloidal particles, nanoparticles are one hundred times smaller, and emulsions stabilized by them can travel a long distance in reservoirs without much retention.
Oil-in-water and water-in-oil emulsions that are stabilized with different surface-coated silica nanoparticles of uniform size have been developed; these emulsions remain stable for several months without coalescence. The wettability of the nanoparticle determines the type of emulsion formed. The phase behavior with respect to the initial water/oil volume ratio (IVR), salinity, nanoparticle concentration and nanoparticle wettability was systematically examined. The emulsions were also characterized by measuring their droplet size and their apparent viscosity. Employing the hard-sphere liquid theory for nano-scale dispersions, the correlation between droplet/droplet interaction forces and droplet/droplet equilibrium separation distances has also been examined.
The Effect of Redox Potential and Metal Solubility on Oxidative Polymer Degradation
Authors: Levitt David B. , Slaughter Will , Pope Gary A. , Jouenne Stephane 
Published: July 2010

Abstract
Oxidative degradation of polymers is a serious concern in the field application of enhanced oil recovery polymers. This study is an attempt to resolve some of the discrepancies in the literature regarding the occurance and extent of this degradation, as well as to present a coherent framework for discussing the multitude of possible radical reactions. Sodium carbonate and bicarbonate are demonstrated to play a key role in stabilizing polymer against multiple reported sources of degradation, and it seems likely that this is due to their effect on iron solubility. Brines containing iron in the reduced state are often obtained from aquifers for use in polymer hydration. These brines are shown to be prone to causing immediate degradation if exposed to air during or after polymer hydration due to the oxidation of the iron. If this cannot be avoided, preaeration may be a feasible strategy to minimize degradation during hydration. However, care must be taken to ensure subsequent degradation is not caused by the injection of a polymer solution containing oxygen into a formation containing iron. For instance, sodium dithionite can be added downstream of the last exposure to oxygen. The use of sodium carbonate may also mitigate degradation due to the oxidation of iron (II) during polymer hydration.
Evaluation and Manufacturing Quality Control of Chemicals for Surfactant Flooding
Authors: Zhao Ping , Howes A. J. , Dwarakanath Varadarajan , Thach Sophany , Malik Taimur , Jackson Adam , Karazincir Oya , Campbell Curt , Waite Jeff 
Published: July 2010

Abstract
The success of chemical flooding rests heavily on the ability to deliver high-quality and repeatable surfactant in the field. While high-quality surfactants can easily be produced at lab scale, high oil recovery can be achieved only if similar quality product is produced at field scale. Scale-up of chemical production from batch-scale laboratory processes to field-scale continuous production requires a comprehensive program to evaluate surfactants produced at the bench-, pilot-plant and commercial scale to establish surfactant performance. Given the difference between batch-scale and continuous processes, small differences in surfactant structure can result thereby inducing differences in phase behavior and consequently oil recovery. Rigorous laboratory work is therefore required to synthesize and characterize surfactant samples in order to understand the correlation between structures/composition and performance in oil recovery. Following laboratory synthesis, pilot-plant studies are used to investigate process variables in order to understand their viability range and their impact on the large-scale product. Other important concerns are: optimal operational conditions, process repeatability, supply chain management, logistics, quality assurance/quality control, feedstock availability and dedicated procurement team. We present a case study for a proposed light oil surfactant polymer flood where a rigorous path for scale-up of surfactants from lab to pilot and finally field scale was evaluated via phase behavior experiments and coreflood testing. We show that phase behavior results are well correlated with coreflood recovery. For EOR, they are superior performance criteria to traditional specifications of physical and compositional properties for quality control. For the two-surfactant system presented herein, 272 surfactant samples, 512 formulations and 20 corefloods were conducted. The results from this large effort were utilized to develop appropriate manufacturing and quality-control processes to ensure the delivery of high-performance surfactants for field application.
Improved Chemical Flood Efficiency by In Situ CO2 Generation
Authors: Shiau B. J. , Hsu Tzu-Ping , Roberts Bruce L. , Harwell Jeffrey H. 
Published: July 2010

Abstract
The purpose of this study is to investigate compounds that can generate carbon dioxide in situ, decrease the viscosity of oil and improve oil recovery. Several chemicals are studied for their potential to generate CO2 when exposed to elevated temperatures. Laboratory results show that ammonium carbamate can produce a significant amount of carbon dioxide when the temperature is elevated to 85° C. In contrast, negligible CO2 is detected while heating up the methyl carbamate to a similar temperature range. Ammonium carbamate is further studied in a one-dimensional sand pack column. Ammonium carbamate results in the production of CO2 in column studies at 80°C and 90° C and also results in a decrease in oil viscosity. The additional injection of a 0.5 PV of 3% ammonium carbamate solution with a polymer + surfactant chemical flood improved crude oil recovery by 9.7% OOIP compared to a polymer + surfactant chemical flood without carbamate. However, there is negligible oil recovery without the presence of surfactant for studies using light oils, decane and Arrow crude oil. The use of carbamate can have a positive impact on the mobility ratio for heavier oil, Elk Petroleum crude oil, by reducing crude oil viscosity. Instead of looking black, the crude oil exiting from the carbamate injected column appeared dark brown and less viscous. This suggests that a property of crude oil was changed by the CO2 generated in the column. Laboratory results also show that AMP (2-Amino-2-methyl-1-propanol) is also a promising candidate for generating carbon dioxide under high temperatures.
Potential for Polymer Flooding Reservoirs with Viscous Oils
Authors: Seright R. S. 
Published: July 2010

Abstract
This paper examines the potential of polymer flooding reservoirs with viscous oils. Higher oil prices, modest polymer prices, increased use of horizontal wells, and controlled injection above the formation parting pressure all help considerably to extend the applicability of polymer flooding in reservoirs with viscous oils. The high mobile oil saturation, degree of heterogeneity, and relatively free potential for crossflow in our target North Slope reservoirs also promote the potential for polymer flooding. For existing EOR polymers, viscosity increases roughly with the square of polymer concentration—a fact that aids the economics for polymer flooding of viscous oils. The key limitation for polymer flood application is not the chemical cost of viscous polymer solutions; instead reduced injectivity is the primary concern. For practical conditions during polymer floods, the vertical sweep efficiency using shear-thinning fluids is not expected to be dramatically different from that for Newtonian or shear-thickening fluids. The overall viscosity (resistance factor) of the polymer solution is of far greater relevance than the rheology.
Interfacially Active SWNT/Silica Nanohybrid Used In Enhanced Oil Recovery
Authors: Villamizar Luis , Lohateeraparp Prapas , Harwell Jeffrey , Resasco Daniel , Shiau Ben 
Published: July 2010

Abstract
Single-Walled-Carbon-Nanotube (SWNT)-Silica nanohybrid particles are a very promising material that could be used in a near future for enhanced oil recovery because of their interfacial activity. The mechanism used to recover additional oil in this case would be to deliver catalytically active nanohybrid particles to the O/W interface, where they would react with and modify the oil properties to mobilize the oil in the reservoir. To demonstrate the basic principle, aqueous nanohybrid particle dispersions were evaluated by looking at the effect of pH, salt, surfactant and polymer. The results showed that pH and salt did not have significant effect on the dispersion stability of nanohybrid particles. Although surfactant could improve the dispersion stability, it reduced the interfacial activity of the nanohybrid particles, causing them to stay in the aqueous phase. The best nanohybrid particle dispersion stability was found upon polymer addition, where the dispersions were stable for more than a week even at low polymer concentration (50 ppm).
After the best conditions for dispersions stability were determined, one-dimensional-sand-pack studies were performed to evaluate the flow of the nanohybrid particles through porous media. The results showed that the most of the nanohybrid particles could pass through a column packed with glass beads while a measurable fraction of the particles were retained in the column packed with crushed Berea. When the columns contained a residual saturation of decane, additional nanohybrid particles were retained at the oil/water interface in both media (glass bead and crushed Berea sand packs). The sand pack studies showed that not only can the nanohybrid particles flow through porous media, but also about half of the particles injected will go the O/W interface when the porous medium contains a residual saturation of hydrocarbon, where they could be used to support a catalytic conversion of components of the oil.
CO2-Soluble Surfactants for Improved Mobility Control
Authors: Xing Dazun , Wei Bing , Trickett Kieran , Mohamed Azmi , Eastoe Julian , Soong Yee , Enick Robert 
Published: July 2010

Abstract
Several commercially available, non-ionic surfactants have been identified that are capable of dissolving in CO2 in dilute concentration at typical MMP conditions and, upon mixing with brine, stabilizing CO2-in-water or CO2-in-brine emulsions or foams. These surfactants include water-soluble branched alkylphenol ethoxylates, linear alkylphenol ethoxylates, and branched alkyl ethoxylates. At 25 °C, the solubility of these surfactants in liquid CO2 at ~1300 psia (~9 MPa) is 0.02 – 0.10 wt%. When equal volumes of liquid CO2 and brine (5wt% NaCl) are mixed with these surfactants, an opaque, white emulsion forms that initiallyfills the entire high pressure view cell. This emulsion collapses, yielding a clear aqueous zone below the emulsion as the brine drains from the continuous films of surfactant-stabilized brine that separate the cells of dense CO2, and a clear CO2 zone above the emulsion as the droplets of CO2 coalesce. The stability of these emulsions, as measured by the rate of their collapse, is strongly influenced by the architecture of the surfactant. The most stable emulsions were achieved with water-soluble, branched alkylphenol ethoxylates, such as nonylphenol ethoxylates with 9-15 ethylene oxide repeat units, and linear alkylphenol ethoxylates, which yielded CO2-in-brine emulsions containing 9-23vol% brine that were stable for more than five hours.