bluuebunny/crossref_metadata_2025_split huggingface dataset:
Liquid Screen: Pickering Emulsion Templating as an Effective Route for Forming Permeable and Mechanically Stable Void-Free Barriers for Hydrocarbon Production in Subterranean Formations
Authors: Ikem V. O. , Menner A. , Bismarck A. , Norman L. R. 
Published: September 2011

Abstract
Gravel packs, most commonly occurring as sand slurries, are conventionally employed as a permeable solid layer in the annulus between a production screen and walls of the wellbore in weakly consolidated subterranean formations (Powell et al. 2006). Gravel packing is a well-known technique for sand control, whereby unconsolidated fines produced from the soft formation are filtered away from the production fluids (Penberthy and Shaughnessy 1992; Saucier 1974; Powell et al. 2006; Tiffin et al. 1998). Unconsolidated fines are highly challenging, as they are expensive to dispose of and can cause erosion of surface equipment, casing failure, clogging of production pipes, and production loss (Penberthy and Shaughnessy 1992; Sparlin and Hagen 1985). However, gravel packs can be problematic. Bridging of sand particles within the gravel pack can create voids, which can result in mechanical failures or significantly reduce the effectiveness of gravel packs to restrain fines from flowing along with the hydrocarbons produced (Suman 1974; Tiffin et al. 1998; Powell et al. 2006).
As an alternative, this paper presents a pioneering method to prepare void-free and mechanically sound permeable barriers in subterranean formations as an alternative to gravel packing. The method of preparation involves the curing of Pickering water-in-oil medium- or high-internal-phase emulsions containing monomers in the annular space between a rock formation and pipe. The emulsions were prepared by simply adding low amounts of nonionic surfactant and dispersant to premade Pickering emulsions, which were stabilized by oleic-acid (OA) modified silica particles (Ikem et al. 2008). The resulting solid materials, known as "poly-Pickering-M/HIPE,"have a gas permeability of up to 2.6 darcies and are highly interconnected and permeable to hydrocarbons (Ikem et al. 2010b). This paper shows that it is possible to tailor the gas permeability and mechanical performance of the permeable barrier by altering the emulsion internal-phase volume, the volume of Hypermer 2296 added to the premade Pickering emulsion, and the composition and constituents of the continuous monomer phase; styrene, divinylbenzene (DVB), and poly(ethylene glycol) dimethacrylate (PEGDMA) were used in the monomer phase.
Stand Research and Analysis of Average-Integral Characteristics of Submersible Centrifugal Pumps Operating at Gas-Liquid Mixtures
Authors: Drozdov A. N. , Verbitsky V. S. , Lambin D. N. , Dengaev A. V. 
Published: September 2011

Abstract
One of the major complicating factors in the pumping operation of oil wells is a high free gas content in the pumped fluid at the ESP’s intake.
In the case of compressible media pumping by the blade machinery it is necessary to take into account the change in the density of the pumped medium with increasing pressure for determine the pump’s head.
On this basis, for ESP’s operating at liquid-gas mixture with the compressibility it is required to calculate the values of the pump head on the mixture and the corresponding average-integral value of mixture’s capacity by integration from the intake pressure to the discharge pressure.
The stand investigation was performed and ESP’s average-integral characteristics were obtained on the model gas-liquid mixtures "water – surfactant – gas" at different intake pressures. Consideration of the ESP’s average-integral curves for low-viscosity oil-gas mixtures showed that they are characterized by essentially the same features as on the mixtures "water – surfactant – gas". Average-integral pump performances "head – flow rate" for homogeneous liquids and gas-liquid mixtures are not dependent on the density of the pumped fluid and, consequently, coincide in the case cavitation-free operation, provided that the viscosity is so small that they do not have a noticeable influence on the pump characteristics. If the curves on the gas-liquid mixture are below the pump characteristics on a homogeneous liquid, it is evidence of the development artificial gas cavitation in the pump. The average-integral curves invariance with respect to the mixture density can compare the pump’s characteristics with a different number of stages in mixtures with dissimilar coefficients of solubility of gas and integrate consideration of pump’s performances with different values of the average density of gas-liquid mixture.
The Effect of Chemistry and System Conditions on Hydrate Interparticle Adhesion Forces Toward Aggregation and Hydrate Plug Formation
Authors: Aman Zachary M. , Aspenes Guro , Sloan E. Dendy , Sum Amadeu K. , Koh Carolyn A. 
Published: September 2011

Abstract
The adhesion force between two cyclopentane hydrate particles was directly measured using an improved micromechanical force apparatus. Adhesion forces decreased between 22 and 87% with the addition of approximately 1000 ppm of various carboxylic acid derivatives. The effect of simple, saturated carboxylic acids (such as decanoic acid) may be primarily explained by a decrease in water-oil interfacial tension. More complex carboxylic acids, such as L-lysine and D-tyrosine amino acids, migrate slowly to the water-oil interface and subsequently may be ineffective at weakening the capillary water bridge between hydrate particles in the 30-second formation/destruction timescale. A 4-membered polynuclear aromatic carboxylic acid (1-pyreneacetic acid) exhibited a decreased adhesion force larger than the prediction from decreased interfacial tension, suggesting an alteration in hydrate surface wettability. We present a numerical solution of one hydrate slurry viscosity model for a simple pipeline scenario, where the difference in adhesion force between mineral oil and 1-pyreneacetic acid can shift shear requirements by one order of magnitude.
Modelling the Application of Scale Inhibitor Squeeze Enhancing Retention Additives
Authors: Vazquez O. , Thanasutives P. , Elliasson C. , Fleming N. , Mackay E. 
Published: September 2011

Abstract
The most common method for preventing scale formation is by applying a scale inhibitor (SI) squeeze treatment. In this process, a scale inhibitor solution is injected down a producer well into the near wellbore formation. In the last few years, several publications have presented experimental results, field data and treatment methods showing enhanced squeeze lifetime, due to use of squeeze enhancers.
The main purpose of this paper is to model the effect of SI retention enhancing additives. These additives are normally deployed in reservoirs, where the SI shows poor retention in the formation matrix, in order to reduce the well intervention. In the last few years, a number of techniques to enhance the SI retention have been reported in the literature, such as precipitation squeezes using calcium and/or pH increasing additives, use of additive package that enhances SI adsorption by cross-linking and the injection of non-damaging concentrations of kaolinite, calcium carbonate and organosilane (a solids fixation agent). Specifically the effect of the SI retention enhancer is modelled as a function of the adsorption level of the additive. A sensitivity study is then presented of the effect of deploying the additive in the different stages; normally they are deployed in the preflush stage. However, the aim of this paper is to investigate how the treatment could be optimized to achieve the longest squeeze lifetime with a fixed amount of additive. Example of modelling a specific field treatment injecting organosilane is included. The results are compared with the field return profiles and clearly demonstrate the value such modelling can bring to the interpretation and design of field squeezes.
Novel Polymeric Additives to Improve Oil Sands Tailings Consolidation
Authors: Watson Philip , Farinato Raymond , Fenderson Thomas , Hurd Michael , Macy Pat , Mahmoudkhani Amir 
Published: September 2011

Abstract
It is estimated that the Athabasca Oil Sands in Alberta, Canada, contain 1.7 trillion barrels of oil, but producing one barrel of oil from surface-mined oil sands also produces 1.8 metric tons of solid tailings suspended in 2 m3 of water. Traditionally, tailings slurries were discharged into settling ponds, where solids slowly settled over periods of decades or longer. Since Canadian ERCB Directive 74 went into effect on 1 July 2010, however, regulatory pressure to quickly and efficiently separate tailings from the water has mounted.
Directive 74 mandates that by 1 July 2012, 50% of tailings solids must be removed from waste streams. Furthermore, the captured solids should be trafficable after five years, defined as possessing a shear strength of at least 10 kPa. The flocculation performance of chemical additives ranging from inorganic salts to high molecular weight organic polymers has been previously assessed, but a procedure for meeting Directive 74 is still uncertain because any proposed solution must deal with a wide range of water quality conditions, mineralogical substrates, and particle sizes.
Bench-scale evaluations of novel polymeric additives on Athabasca oil sands were performed in both 1-L graduated cylinders and a thickener. The compactness of captured solids was measured by density and solids content, dewatering was assessed by capillary suction times, and the shear strength of flocculated particles was determined rheologically. The additives were observed to greatly improve flocculation, dewatering, and growth of shear strength relative to conventional polymer treatments.
Improved Microbial Control Programs for Hydraulic Fracturing Fluids Used During Unconventional Shale-Gas Exploration and Production
Authors: Enzien Michael V. , Yin Bei , Love Donald , Harless Michael , Corrin Edward 
Published: September 2011

Abstract
Biocide efficacy studies targeting extended contact times, 7 days, and elevated temperatures, 80° C, led to the discovery of a synergistic combination of Dimethyl Oxazolidine (DMO) and glutaraldehyde. When applied together in specific ratios, most notably a 1:4 ratio of glutaraldehyde to DMO, these two chemistries exhibited superior performance after extended exposure relative to traditional biocide treatments utilizing chemicals such as THPS, glutaraldehyde, and glutaraldehyde/alkyl dimethy benzyl ammonium chloride (ADBAC) blends. The combination of glutaraldehyde and DMO applied in a 1:4 ratio was able to achieve equal performance with lower combined actives. The result of this synergy has a twofold impact on the environmental footprint: it requires less overall biocide for the same level of control, and DMO has a more favorable eco-toxicity profile compared to conventional organic biocides. Field trials on eleven wells and 4 separate well pads in the Marcellus Shale area were treated with the Glutaraldehyde and DMO combination and evaluated using various microbial detection techniques. The benchmark for performance was set by the prior standard chemical treatment in the same shale formation area which utilized the biocide combination, 42.5% active glutaraldehyde and 7.5% active ADBAC blend. Seven wells on three separate well pads treated with Glut/ADBAC were used for comparison to the test wells. The wells treated with the Glut/ADBAC were all dosed at a rate of 300 ppm active ingredient (600ppm product), and the wells used to test the glutaraldehyde/DMO combination treatment were dosed at 200 ppm active (285ppm product). The results of the field trials showed equal or slightly better performance with the combination treatment while utilizing 33% less active chemical, and yielding a reduction of 50% less biocide product applied.
Stabilizing Viscoelastic Surfactants in High Density Brines
Authors: van Zanten Ryan 
Published: September 2011

Abstract
Viscoelastic surfactant (VES) systems are the preferred gelling and viscosity generating agents for fluids used in the production zone due to their non-damaging effects on the reservoir. Polymer gels have relatively higher rock retention values and can often damage the invaded zone, in most cases requiring acid treatment to remove. In contrast, VES systems behave as "equilibrium" or "living" polymers and their viscosity can be reduced by contact with the produced hydrocarbons or with an internal breaker. This can eliminate the need for remedial treatments, greatly reducing operating cost/time and damage to the formation.
Cationic, anionic and catanionic VES systems have historically demonstrated limitations in high density brines. Electrostatic screening generally reduces the viscosity or causes phase separation. Many surfactants generally have low salt tolerance and minimal to zero tolerance of divalent brines. Most surfactants exhibit a drastic decrease in viscosity after a certain concentration of salt is reached and even phase separation in some cases.
A novel method has been found to stabilize different VES packages in high density completion brines. By controlling the curvature of surfactant aggregates using low molecular weight surfactant polymers, nanometer scale manipulation of the phase behavior is achieved. We have viscosified mono- and divalent high density brines using cationic, anionic and catanionic mixtures that were previously considered ineffective. This unlocks a vast range of surfactants for use in high density completion brines, fracturing/stimulation/acidizing fluids and sand control operations.
This paper details the laboratory work performed to develop VES packages for fluids ranging from freshwater to completion brines. Extensive rheology experiments have been run on several fluids showing the viscoelasticity of these systems. The self-breaking nature of VES systems when in contact with hydrocarbons or exposed to a built-in breaker has also been demonstrated by laboratory experiment.
Studies on the Chemical Stability of Glutaraldehyde in Produced Water
Authors: McGinley Heather R. , Enzien Michael V. , Jenneman Gary , Harris Jennifer 
Published: September 2011

Abstract
Description Glutaraldehyde is one of the few biocidal actives approved for use in North Sea operations, and has long been used to protect crude oil pipelines from microbial fouling. However, glutaraldehyde degradation has been observed in produced water (PW). In an effort to understand and control this degradation, stability tests were performed in the laboratory. Specific factors which accelerate degradation were identified. Strategies for dosing glutaraldehyde optimally to maintain microbial control in PW will be discussed.
Application This study is applicable to microbial control and asset integrity in produced water applications. We aim to develop a better understanding of how glutaraldehyde behaves in complex systems so dosing guidelines can be made more robust and customized to specific situations.
Results, Observations, and Conclusions Analysis of glutaraldehyde stability was performed in field and synthetic PW samples. The degradation profile was similar in both water types, indicating a good match between the field and synthetic samples. The most significant factors in glutaraldehyde degradation were temperature and the presence of ammonium chloride. Other factors were also significant, as indicated by the fact that glutaraldehyde in synthetic seawater containing ammonium chloride degrades far slower than in PW at the same temperature and ammonium chloride concentration. Additionally, lower starting concentrations of glutaraldehyde degraded to a greater extent than higher concentrations. This suggests that batch dosing will be more effective than continuous low-concentration doses.
Significance Protection of assets and hydrocarbons from microbial contamination and fouling is a major concern in the oilfield. While effective chemicals for microbial control are readily available, their use is often limited by regulatory, environmental, and compatibility concerns. It is therefore very important to understand the chemistry of the available products in a given system such that the most appropriate treatment can be chosen and applied to maintain adequate microbial control.
Wettability Alteration and Foam Mobility Control in a Layered 2-D Heterogeneous System
Authors: Li Robert F. , Hirasaki George J. , Miller Clarence A. , Masalmeh Shehadeh K. 
Published: September 2011

Abstract
In a layered 2-D heterogeneous sandpack with 19:1 permeability contrast that was preferentially oil-wet, the recovery by waterflood was only 49.1% of original oil-in-place (OOIP) due to injected water flowing through high-permeability zone leaving low-permeability zone unswept. In order to enhance oil recovery, an anionic surfactant blend (NI) was injected that altered the wettability and lowered the interfacial tension (IFT) and consequently enabled gravity and capillary pressure driven vertical counter-current flow to occur and exchange fluids between high- and low-permeability zones during a 42-day system shut-in. Cumulative recovery after a subsequent foamflood was 94.6% OOIP even though foam strength was weak. Recovery with chemical flood (incremental-recovered-oil/waterflood-remaining-oil) was 89.4%. An alternative method is to apply foam mobility control as a robust viscous force dominant process with no initial surfactant injection and shut-in. The light crude oil studied in this paper was extremely detrimental for foam generation. However, the addition of lauryl betaine to NI at a weight ratio of 1:2 (NI: lauryl betaine), made the new NIB blend a good foaming agent with and without the presence of the crude oil. NIB by itself as an IFT reducing and foaming agent is shown to be effective in various secondary and tertiary alkaline/surfactant/foam (ASF) processes in water-wet 1-D homogeneous sandpacks, and in an oil-wet, heterogeneous layered system with 34:1 permeability ratio.
Methodology for Dimensioning of the Resources for Construction of the Oil Wells
Authors: Filardo J.. , Morooka C.. 
Published: September 2011

Abstract
This paper proposes a new methodology for determining the quantity of physical resources used for the construction of oil wells in relation to the methodology that employs a rough assessment of the curve of resource needs in the time it does not take into account the risks and gains for the business. With emphasis on material resources, and using knowledge of geo-engineering, petroleum engineering, production engineering, economic engineering, project management, artificial intelligence and programming, an equation was established with terms representing the potential revenue from the wells and the costs of excess or the lack of resources in the planning period which enables the knowledge of the optimum quantitative of resources for the company.
The design method has been tested to determine the quantity of pipe casing used in Brazilian exploration wells planned for 2009, based on the configuration of the pre-salt wells.
It is concluded that this methodology has significant gains over the conventional method of analysis by allowing the decision makers to know how much will be your revenue and associated costs, risks and opportunities.
Effect of Water Blocking Damage on Flow Efficiency and Productivity in Tight Gas Reservoirs
Authors: Bahrami Hassan , Rezaee M. Reza , Nazhat Delair , Ostojic Jakov , Clennell Ben , Jamili Ahmad 
Published: September 2011

Abstract
Tight gas reservoirs normally have production problems due to very low matrix permeability and significant damage during well drilling, completion, stimulation and production. Therefore, they might not flow gas at optimum rates without advanced production improvement techniques.
The main damage mechanisms and the factors that have significant influence on total skin factor in tight gas reservoirs include mechanical damage to formation rock, water blocking, relative permeability reduction around wellbore as a result of filtrate invasion and liquid leak-off into the formation during fracturing operations. Drilling and fracturing fluids invasion mostly occurs through permeable zones or natural fractures and might also lead to serious permeability reduction in the rock matrix that surrounds the wellbore, natural fractures, or hydraulic fracture wings.
This study represents evaluation of water blocking damage in tight gas formations, and the influence on core flow efficiency and well productivity. Core scale reservoir simulations were carried out based on a typical Western Australia tight gas reservoir in order to numerically model liquid invasion during overbalanced, balanced and underbalanced drilling, and the effect on gas production in clean-up period. The simulation results describe how water blocking reduces near wellbore permeability and affects well productivity and gas recovery from tight gas reservoirs.
Original-Gas-In-Place Sensitivity Analysis of the Manville Group in the Western Canada Sedimentary Basin
Authors: Contreras Oscar , Aguilera Roberto 
Published: September 2011

Abstract
A sensitivity analysis of the Original-Gas-In-Place (OGIP) in the Manville group of the Western Canada Sedimentary Basin (WCSB) is carried out by using Star Plots in order to determine (1) what parameters have that largest impact on the gas volume estimation, (2) what is the error in the volume estimation, and (3) what is percent error in the choices of effective porosity and Archie’s exponents m and n on water saturation. The Manville group in the WCSB contains a very large resource of natural gas that was quantified to be in the order of 1500 tcf (Masters, 1984).
The gas in place calculations are based on the volumetric equation that takes into account area (A), net pay (h), effective porosity (PHI), true resistivity of the formation (Rt), water resistivity (Rw), porosity exponents "m" and "n," and initial pressure (Pi).
The sensitivity analysis is carried out by choosing possible errors around each input parameter. This permits to concentrate evaluation efforts on the tools and data that have the largest effect on the calculated values of OGIP.
It is concluded that intuition does not necessarily distinguish the data with the largest impact on the calculations. For example, the water resistivity (Rw) is the parameter with the smallest impact on OGIP estimations presented in this study. Based on results, three new polynomial correlations are developed to represent the effect of porosity (PHI) and the m and n exponents on water saturation estimations for the Manville Group. These correlations will improve significantly the way in which uncertainty and risk associated with reserves estimation are quantified.
A Study of Completion Effectiveness in the Williston Basin
Authors: Panjaitan M. L , Cherian B. V , Mata D. , Krishnamurthy J. , Lewis R 
Published: September 2011

Abstract
The evolution in oilfield technology to enable the drilling of longer horizontal wells and increased stimulation effectiveness via isolation has resulted in significant productivity gains. The challenges associated with data gathering, increased well count and understanding connectivity of the recently recognized additional reservoir (Three Forks) has generated concerns regarding the development strategy in the Williston Basin. In order to understand a development strategy it is crucial to characterize fracture properties and reservoir properties. A single well model is developed to capture current well performance to understand the impact of the range of fracture geometries and spacing on production performance. Modeling results and fracture pressure data are also presented to demonstrate the effectiveness of fracture initiation techniques, isolation techniques and number of clusters on fracture geometry generation. The paper presents results utilizing single well modeling techniques (using fracture history matching, production history matching and forecasting) to understand and differentiate reservoir quality, reservoir connectivity and completion effectiveness with the aim of understanding the direction in which completion changes must evolve.