bluuebunny/crossref_metadata_2025_split huggingface dataset:
Flotow, Luise von (Org.). <em>Translating Women</em>. Ottawa: University of Ottawa Press, 2011, & Farzaneh Farahzad; Luise von Flotow (Org.). <em>Translating Women</em>: Different Voices and New Horizons. Routledge: New York, 2017.
Authors: Barboza Beatriz Regina Guimarães 
Published: June 2018

Dentre os trabalhos na intersecção dos Estudos da Tradução com os Estudos de Gênero, as duas publicações sob título de Translating Women representam ótimos exemplos da aplicabilidade e aprofundamento teórico dos temas abordados por esse campo de estudos. Se o primeiro volume (2011) trouxe uma grande variedade de enfoques, o segundo (2017) foi uma reação positiva às críticas feitas ao primeiro, trazendo trabalhos de fora do eixo América do Norte — Europa, efetivamente abrindo novos horizontes e percebendo a importância dos contextos locais e suas próprias teorias para poder estabelecer uma rede de feminismo transnacional.
Nord, Christiane. <em>Análise textual em tradução</em>: bases teóricas, métodos e aplicação didática, com tradução e adaptação de Meta Elisabeth Zipser et al. São Paulo: Rafael Copetti Editor, 2016.
Authors: Eleutério Rosangela Fernandes 
Published: June 2018

O livro "Análise textual em Tradução: bases teóricas, métodos e aplicação didática" da teórica em tradução Christiane Nord, foi lançado em 2016 pela Rafael Copetti Editor e traduzido para o português por Meta Elisabeth Zipser. A obra trata sobre vários elementos inerentes a tradução e traz reflexões sobre a teoria e sua prática.
A Novel View of Barium Sulfate Deposition in Stainless Steel Tubing
Authors: Lu Alex Yi-Tsung , Ruan Gedeng , Harouaka Khadouja , Sriyarathne Dushanee , Li Wei , Deng Guannan , Zhao Yue , Wang Xing , Kan Amy , Tomson Mason 
Published: June 2018

Abstract
Deposition of inorganic scale has always been a common problem in oilfield pipes, especially in raising safety risk and producing cost. However, the fundamentals of deposition mechanism and the effect of various surface, temperature, flow rate and inhibitors on deposition rate has not been systematically studied. The objective of this research is to reveal the process of barium sulfate deposition on stainless steel surfaces.
In this work a novel continuous flow apparatus has been set up to enable further investigation of deposition rate, crystal size and morphology and the effect of scale inhibitor. In this apparatus supersaturate barium sulfate solution is mixed and passed through a 3 feet stainless steel tubing with ID = 0.04 inch or 0.21 inch at 70 to 120 degree C. The barium concentration is measured at the effluent to quantify the concentration drop. After 1 to 200 hours the tubing is cut into pieces to measure the barite deposition amount and observe the barite crystal morphology using SEM.
Under the experimental conditions, the deposition rate along the stainless steel tubing can be modelled by second order crystal growth kinetics, the SEM micrograph also shows that most of deposited barite is micrometer sized crystals. The highest deposition rate happens at the beginning of the tubing even before the expected induction time of bariums sulfate. The results indicated that the deposition happens even before the mixed solution is expected to form particles, which suggest that the heterogeneous nucleation might be the dominate mechanism in the initial stage, then crystal growth takes place and governs the deposition.
The mechanism of scale attachment to tubing surface has never been well-understood. The apparatus in this work provides a reliable and reproducible method to investigate barium sulfate deposition. The findings in this research will enhance our knowledge of mineral scale deposition process, and aid the use of inhibitors in mineral scale control.
The Effect of Surface Material on the Mechanics of Calcium Carbonate Scale Deposition
Authors: Harouaka Khadouja , Lu Yi Tsung , Ruan Gedeng , Sriyarathne H. Dushanee , Li Wei , Deng Guannan , Zhao Yue , Wang Xin , Kan Amy T , Tomson Mason 
Published: June 2018

Abstract
Calcium carbonate deposition experiments were carried out by pumping a brine solution through PTFE plastic, carbon steel, and 316 stainless steel tubing at 150°C and at a maximum SICaCO3 of 1.36. The kinetics of deposition were inferred from the variation of HCO3- concentration in the effluent with changing flow rate. The inhibition kinetics were determined before, during, and after the addition of NTMP inhibitor into the system. On the metal surfaces, deposition occurred within 10 minutes of the start of the experiment and had similar behavior with changing flow rate, whereas deposition did not begin on the PTFE surface until 30 minutes had passed. No more than 1ppm of NTMP was sufficient to completely halt deposition in the PTFE and stainless steel experiments, whereas up to 2 ppm of NTMP was required in the carbon steel experiment. The deposition kinetics were indistinguishable between the metal surfaces, and were ultimately similar on the smoother hydrophobic PTFE surface once an initial coating of scale had developed. The inhibition efficiency of the NTMP was negatively affected by the corrosion products produced in the carbon steel experiments, assumed to be primarily dissolved Fe (II). Inhibitor retention was higher in the metal surfaces than in the PTFE, possibly due to the preferential adsorption of the NTMP to the surface of the Fe rich steel tubing. Our results suggest that it is the hydrodynamics of brine in the tubing, controlled by flow rate, and the SI that are the main factors controlling scale deposition. Calcium carbonate scale attachment occurs via heterogenous nucleation directly onto the surface of the tube when the brine solution approaches oversaturation from a state of equilibrium with respect to calcium carbonate. The mechanism of inhibition in our system is likely to proceed through the formation of Ca- and Fe-NTMP complexes that either poison the growth surfaces of the scale, or drop the SI of the calcium carbonate by reducing the acitivity of free Ca in the brine.
Recent Experience in Squeeze Treating Huff and Puff Wells for Control of Steamflood Generated Calcium Carbonate Scale
Authors: Thornton Alex , Belhimer Yaz , Smith Ian , Subramaniyan Aravind 
Published: June 2018

Abstract
Steamflooding technology introduction into hydrocarbon recovery operations often brings with it unwanted unavoidable mineral scaling challenges. In this example, steamflood generated calcium carbonate scale caused downhole equipment failure during cyclical steamflood stimulation (CSS) operations. The precipitated scale was effectively removed via mineral acid tubing wash, however mineral acid use for ad-hoc scale dissolving duty added significantly to the corrosion burden of well production tubing strings already regularly exposed to aggressive high concentration mineral acid during near wellbore matrix stimulation treatments. Scale inhibitor squeezing was proposed as a proactive alternative to mineral acid for downhole scale mitigation, and is the subject of this case history. The Middle Eastern heavy oil (HO) field has experience in employing scale inhibitors for topside scale control, but has limited experience in scale squeezing, and no experience of scale squeezing cyclical steam flooded wells. The initiative therefore presented some interesting challenges with respect to the Scale inhibitor selection (thermal stability concerns, compatibility and calcium carbonate efficacy concerns), where to place the scale squeeze in the CSS treatment programme, the squeeze design and its placement within the CSS well, and introduction and execution of routine well scaling health monitors for assessing the performance of the scale squeeze across the full CSS life-cycle.
Detailed bullheaded scale squeeze designs were prepared for two pilot HO field CSS wells that had experienced CaCO3 scaling. Once prepared, the squeeze treatments were quickly scheduled and executed without significant issue - either during treatment application or post-squeeze/steamflood return. The well brine monitors (brine ion composition, residual scale inhibitor and suspended solids) revealed interesting trends during the surveillance phase, but most importantly showed that the scale squeezes performed according to design and successfully maintained the wells free of CaCO3 scale, up to and including the 266 days post-steamflood, at which point routine well produced water sampling was discontinued. After 360 days (at the final review meeting) the field operators advised that both squeezed wells were still in operation and had experienced no scaling downtime.
Novel Laboratory Test Method and Field Applications for Silica/Silicate and Other Problematic Scale Control
Authors: Lu Haiping , Brooks Johnathon , Legan Rick , Fritz Steven 
Published: June 2018

Abstract
The formation of silica and silicate scales caused troublesome issues in various water-handling systems, including steam generators, geothermal wells, and waste-water disposal systems. Recently, a produced water with over 300 ppm of silica, and a spent brine off the strong acid cation (SAC) softeners containing high levels of calcium (Ca), barium (Ba), and magnesium (Mg) were commingled in the production wells. The mixing of these two waters induced silicate as well as other scales, including calcite, barite, etc. In order to provide effective scale inhibition when these waters are mixed, effective scale inhibitors for both silicate and other scales were requested for evaluation.
In this paper, scale inhibitor chemistries for preventing both silica/silicate and other scales were reviewed and the possible synergistic effects were assessed by Design of Experiment (DOE) software. DOE is a systematic method to determine the relationship between several factors, i.e. various chemistries and the performance of formulations under designed application conditions. Selected chemicals were formulated for control of both silica/silicates and other scales, and their performances were evaluated by a Kinetic Turbidity Test (KTT). The KTT is a novel laboratory test method using an Ultraviolet-Visible (UV-Vis) spectrophotometer to monitor the formation of scales at various dosages of tested products. Bottle tests were also conducted for the comparison of inhibition performance.
Based on the lab testing results from the KTT and the bottle tests, the combined products exhibited good scale inhibition performance for both silicate and other scales. The product was recommended for field applications. Subsequent field applications of this product have provided the desired scale control.
This paper presents the laboratory testing data for scale inhibitor selection for the combination products on both silica/silicate control and other scale control by using the efficient performance evaluation method. It also provides an effective product formulation approach for finding synergetic effects of different products. Successful scale inhibitor implementations in the field applications are also presented in this paper. Both laboratory and field testing results show a good case history for the optimization of the silica/silicate and other scale treatment.
Non-Chemical Methods for Downhole Control of Carbonate and Sulphate Scales - An Alternative Approach to Scale Management?
Authors: Heath Stephen , Bin Ruslan Mohd Zahirin , McKay Eric , Ishkov Oleg 
Published: June 2018

Abstract
The deposition of carbonate and sulphate scales is a major problem during oil and gas production. Managing scale with chemical application methods involving either scale prevention and/or removal are the preferred methods of maintaining well production. However, chemical scale control is not always an option, depending upon the nature of the reservoir and well completion and, in cases of severe scaling, the problem can render chemical treatments uneconomic unless other non-chemical methods are utilised.
A variety of non-chemical scale control methods exist, the most common being injection of low salinity brines or low sulphate seawater (LSSW) using reverse osmosis and a sulphate removal plant (SRP) respectively. In addition, careful mixing of lift gas, produced waters and reinjection, coatings, smart well completions with active inflow control devices (ICD) and sliding sleeves (SS) are other methods.
All of these techniques, including combinations thereof, are currently in use and the advantages and disadvantages of the key techniques are compared to chemical methods for both carbonate and sulphate scale control. A detailed example from a North Sea field demonstrates where downhole chemical scale control has not been required through a strategy of careful mixing of lift gas, brines and produced water re-injection. This was combined with understanding fluid flow paths in the reservoir and their likely breakthrough at production wells.
Consideration is given to the injection of smart brines to scale deep in the reservoir, and data from North Sea chalk fields shows how "in situ" geochemical reactions between the reservoir and the injected fluid can precipitate sulphate scales. The necessity to understand these geochemical reactions and their implications for improved oil recovery and the design of smart injection brines for scale control are discussed.
This paper presents a comprehensive review of non-chemical methods for downhole scale control and discusses how the use of these techniques can provide alternative scale management strategies through minimising or alleviating the need for downhole chemical treatments.
Enhancing Scale Inhibitor Squeeze Retention in Carbonate Reservoirs
Authors: Sutherland Louise , Jordan Myles , Champion Nalco 
Published: June 2018

Abstract
The practice of scale squeeze treatments to oil/gas production wells to prevent inorganic scale formation has been applied for over 30 years and during that period different mechanisms to retain the inhibitor chemical have been evaluated. Many of these studies have focused on sandstone reservoir with less extensive studies carried out on carbonate substrates.
This paper details work carried out using ‘squeeze life enhancer’ chemicals within the Preflush and Overflush stages utilising a co-polymer containing a quaternary amine group to evaluate this chemicals effect on phosphonate scale inhibitor retention process. Phosphonate scale inhibitors are known to provide excellent squeeze lifetimes in carbonate reservoirs due to their strong interaction with the negatively charged formation using hydrogen ion bonding at low pH or calcium ion bridging at higher pH however with the aid of an enhancer chemical it was hoped to help the retention/release process and so provide further improved squeeze lifetimes. The location of the enhancer chemical within the squeeze process was the focus of the study. Enhancing adsorption of the scale inhibitor is not objective of this application study rather ensuring that the retained chemical is released into the flowing brine during production which is a challenge in carbonate reservoirs.
Laboratory work will be presented which evaluates the effect of using a polyaspartate enhancer within either the preflush or overflush stages to extend the lifetime of a commonly applied phosphonate scale inhibitor. These tests have been carried out using pack floods at 85°C with synthetic Middle East produced water and the details of the extension in treatment life observed are correlated to the inhibitor type tested and the sequence of application of the polymer enhancer utilised.
The study shows how the different functional groups within the scale inhibitor interact with the carbonate mineral surface and polymer enhancer to extend treatment lifetimes and so potentially reducing the frequency of squeeze treatments and therefore total cost of operations and it is order of application of these chemicals to the rock surface that prove to be critical to the extension observed.
Effect of Magnesium and Ferrous Ions on CaCO3 Scaling in MEG Regeneration Pre-Treatment
Authors: Ma Xiaoguang , Neteland Marte , Broby Margrethe , Andreassen Jens-Petter , Seiersten Marion 
Published: June 2018

Abstract
Monoethylene glycol (MEG) regeneration may include a pre-treatment to reduce the concentration of cations that tend to induce scaling in the downstream process. This work reproduced pre-treatment conditions in a continuous stirred-tank reactor. The experiments were performed in 50 wt% MEG solutions at 80°C. Divalent cations and alkalinity solutions were dosed into the reactor and the mixed solution was pumped out at controlled rates. Steel rods were inserted into the test solution to measure scaling rates. The growth of scale and particles in bulk solution with varying Mg2+, Fe2+ and SO42− ions were studied as function of supersaturation with respect to calcite.
The experimental results show that crystallization fouling, rather than particulate fouling, is the dominating mechanism controlling the formation of calcium carbonate scale in MEG pre-treatment. The supersaturation at steady state controlled the amount of scale. The presence of Mg2+ retarded the nucleation rate of calcium carbonate and thereby lowered the surface areas available for consumption of Ca2+ and CO32− in in the bulk solution. It resulted in higher CaCO3 supersaturation which promoted scaling. Addition of Fe2+ had little effect on scale formation. At these conditions, the calcium carbonate scale that formed on steel rods and as solids in the bulk were exclusively the aragonite polymorph. Seeding with aragonite reduced the scaling tendency in the experiments where Mg2+ was present. The result indicates that maintaining a large active surface area for growth in the bulk solution can reduce the scale formation.
A Novel Evaluation of Scale Inhibitor Performance against Calcium Carbonate Scaling in the Presence of Iron Sulfide
Authors: Russek Jeffrey , Flores Nicole , Brooks Johnathon 
Published: June 2018

Abstract
Scale inhibitors are commonly used for mitigating scale deposition risks in many oil and gas wells worldwide. Of the various chemistries used for scale inhibition, much research has gone into the various conditions in which each chemistry performs best (i.e. temperature, brine solubility, salinity, etc.)4-6. Furthermore, it is known that dissolved iron (Fe2+ and Fe3+) can hinder the performance of scale inhibitors, some more than others3. Thus, applying this knowledge we can extrapolate which inhibitor chemistries might perform best under a given set of conditions. This knowledge can then be applied regionally where most production comes from the same or similar reservoirs and production conditions.
However, less research has been conducted on the effects of pre-existing iron sulfide deposits on the performance of scale inhibitors. Iron sulfide solids are becoming increasingly problematic in the oil field. The combination of iron sulfide with more conventional scaling deposits and the fact that scale inhibitors are surface active and tend to adsorb onto surfaces can yield very challenging situations. This paper discusses testing conducted on various scale inhibitor chemistries and evaluates how exposure to pre-existing FeS solids may impact performance. The various scale inhibitors were evaluated for inhibition performance against a set of controls (no FeS exposure) utilizing the NACE Standard TM0137-2007 "Laboratory Screening Tests to Determine the Ability of Scale Inhibitors to Prevent the Precipitation of Calcium Sulfate and Calcium Carbonate from Solution (for Oil and Gas Production Systems)" with an additional pre-test procedure to expose scale inhibitors in stock solution to a set weight of reagent grade ferrous sulfide (FeS).
Scale inhibitor chemistries evaluated include two polymers (scale inhibitor A and B) and five phosphorous based scale inhibitors (scale inhibitors C through F). The various configurations tested included: scale inhibitors alone, scale inhibitor plus FeS solids, scale inhibitor without FeS plus crude oil, scale inhibitor plus FeS and crude oil. The inclusion of the crude oil allowed an interface for potential micelle interactions. The results indicate scale inhibitors A, C and G were least affected by the presence of FeS with no regard to the presence of crude oil. With this study a scale inhibitor that worked best in the presence of FeS solids for the customer's field in the Permian Basin, where FeS has become an increasing issue, was recommended. This also allowed the customer to treat the FeS solids issue via the method that works best for them.
Scale Formation and Inhibition Study for Water Injection Wells
Authors: Wang Wei , Wei Wei , Ferrier Neil , Arismendi Nayi 
Published: June 2018

Abstract
Produced water can be routely re-injected into reservoir for purposes including pressure support and environmentally acceptable disposal. Scale prevention and control is required to maintain well injectivity and longetivity. This paper presents a comprehensive scale study to reliably access injection well scaling potential and establish fit-for-purpose/optimal scale management strategy. Field water samples were appropriately collected and characterized. Laboratory testing was well designed/conducted to understand scale formation potential, and determine required scale inhibitor dosage. Study results suggest calcite and silicate scales can be of potential concern, and increase of downhole temperature or/and fluid residence time (e.g., under abnormal operation condition with low injection rate or well shut in) at near wellbore formation can lead to higher scaling risk. Testing results show that one scale inhibitor product (originally recommended by chemical vendor) at high dosage can potentially accelerate scale formation leading to more solid precipitation. Alternative inhibitor products were tested and scale inhibitor selection and treatment strategy was optimized based on testing results.
Halite Challenges and Mitigation in the Bakken- Experience of Managing High Saline Produced Water from Hydraulically Fractured Wells
Authors: Zhang Nan , Schmidt Darren , Choi Wanjoo , Sundararajan Desikan , Reisenauer Zach , Freeman Jack , Kristensen Eivind Lie , Dai Zhaoyi , Kan Amy , Tomson Mason 
Published: June 2018

Abstract
Produced water from the Bakken and Three Forks formations in the Williston Basin is notably high in total dissolved solids, which leads to many well maintenance issues related to halite scaling (salt precipitation). Fresh water is widely used to prevent halite scaling; however, initial treatment programs tend to "overtreat" the problem and leads to high operation and maintenance costs. An effort to improve halite scale management has been explored, which includes identification of wells that need fresh water injection; optimization of the fresh water volumes; minimizing deferred oil production; and preventing other scales associated with the presence of fresh water in the wellbore. Several methodologies have been applied to characterize halite scaling and achieve optimization of fresh water treatments. A scaling prediction model was developed and validated with literature data and field data. The model calculates saturation ratios and optimal fresh water volume, which provides critical inputs for treatment recommendations. Field tests have been conducted to dynamically characterize produced fluids. Results have influenced new methods for treatment and fresh water injection techniques. Halite scale inhibitors have also been examined in laboratory and field tests. This work resulted in optimizing both fresh water and chemical treatment programs to minimize halite scaling. Significant cost savings have been achieved from reduced fresh water usage, thereby lowered produced water disposal.