bluuebunny/crossref_metadata_2025_split huggingface dataset:
Tramas de resistência, linhas de afetos e subversões femininas
Authors: Couto Maria de Fátima Morethy , Malta Marize , Oliveira Emerson Dionisio Gomes de 
Published: June 2023

A presente edição da Revista MODOS: Revista de História da Arte conta com dezessete textos inéditos. Destacamos os artigos do dossiê "Feminismos em campos expandidos", proposto pelas pesquisadoras Ana Paula Cavalcanti Simioni; Patricia Mayayo, que se somam a um crescente corpo de pesquisas que intentam transformar a(s) história(s) da arte por meio de metodologias que redefinam os limites geográficos e culturais da disciplina e da relação entre arte e feminismos em diferentes países ou regiões.
ARAP MÜZİK KONGRESİ (1932): TARİHSEL DEĞİŞİM, MİLLİ KİMLİK VE ÖZNEL ANLATILAR
Authors: ÖNER Onur 
Published: June 2023

Bu çalışma, 1932’de Kahire’de düzenlenen Arap Müzik Kongresi’ni Mısır’ın I. Dünya Savaşı’ndan itibaren yaşadığı siyasal ve toplumsal gelişmelere paralel olarak ele almaktadır. İki dünya savaşı arasında dolaşımda olan Mısırlılık, Mısır milliyetçiliği ve Pan-Arapçılık, modern Mısır kimliğinin temsil alanlarından
birisi olarak düşünülen Mısır müziğinin yeniden yapılandırılmasının arkasında işleyen düşünce biçimleriydi. Çalışma, kongre günlerini Arap Müzik Kongresi’nin de belirleyici dinamikleri olduğunu ileri sürdüğü ideolojik ve kavramsal tartışmaların penceresinden değerlendirmeyi önermektedir. Kimi katılımcıların kongre esnasında tuttukları günlükler ve yakınlarına hitaben yazdıkları mektuplar çalışmanın yoğunlaşacağı temel kaynaklardır. Bu metinler, olabildiğince rahat ve hatta kaygısız denilebilecek bir üslupla kaleme alınmış olmalarından ötürü kongrenin teknik seviyesi yüksek raporları ve makalelerinden daha renkli ve özneldirler. Kongrede yaşanan tartışmalar, oluşan ihtilaflar, hizipleşmeler ve rekabetin doğurduğu gerginlikler yalın bir dil ve doğallıkla kâğıda dökülmüşlerdir. Bu metinler, sahip oldukları birbirinden farklı bakış açıları ve çok katmanlı anlam dünyalarıyla kongrenin müzikolojik bağlamının dışına taşacak analizlere kapı aralayacaklardır.
Effective Stimulation of a Limited Entry Liner (LEL) Well Using a Leading Viscoelastic Diverter Acid System
Authors: Morrow Timothy I. , Fawzy Ahmed Mohamed , Ryan Abraham , Arali Vaishak , Alnaqbi Maryam , Noordin Firdaus Bin Mohamed , Alshehhi Waleed , Naseem Arslan , Zayed Eltantawy Hamida , Araque Gustavo , Belkadi Wafaa 
Published: June 2023

Abstract
A horizontal water injection well with limited entry liner (LEL) completion in an onshore Middle East carbonate reservoir was stimulated with HCl using a large volume of viscoelastic diverter acid (VEDA) fluid system ahead of the main acid stage. The VEDA stage was needed to deliver sufficient acid volumes to the toe of the well resulting in a significant increase to the injectivity index and more even distribution of injected water across the horizontal drain.
VEDAs have been successfully used to achieve diversion in openhole and casedhole perforated completions for years. However, VEDA stages have rarely been used in LELs because the liner design typically ensures even distribution of acid across the completion. In this case, due to a large contrast in permeability between the heel and toe of the well, the mechanical diversion of the LEL is enhanced chemically by including VEDA for even distribution of injected fluid to all compartments. Near-wellbore modeling showed that the inclusion of a VEDA stage ahead of the main acid stage could provide temporary diversion of acid from the heel to the toe compartments, resulting in more uniform wormhole length and stimulated skin profiles.
The VEDA was pumped successfully through the small 4-mm openings in the liner, and the stimulation job was able to be pumped at the maximum rate achievable by the pumping equipment. The stimulation increased the injectivity index by approximately a factor of 4. The VEDA stage produced more than 600 psi of diversion pressure in the heel compartments. The post-stimulation injection log confirmed the success of the stimulation by showing more even distribution of injected water across the entire horizontal drain, despite the contrast in the native (unstimulated) permeability between the heel and toe compartments.
Experimental Study and Quantitative Evaluation on Oil Recovery from Different Pore Sizes of Tight Sandstone Reservoirs Under N2 and CO2 Flooding
Authors: Li Xiang , Yang Weipeng , Wang Yanqing , Huang Kai , Luo Weijiang , Yu Haiyang , Lu Jun 
Published: June 2023

Abstract
The low permeability of tight sandstone reservoirs limits the application of water flooding to improve oil recovery. Owing to their properties, N2 and CO2 have been used in gas flooding to increase the oil recovery from these reservoirs, achieving good results. However, the oil-displacement mechanism at different pore sizes in tight sandstones during N2 and CO2 flooding, especially the quantitative characterization and comparison of the displacement effects of gas flooding, remain unclear. In this study, gas flooding experiments were conducted combined with Nuclear Magnetic Resonance (NMR) to simulate the distribution characteristics of crude oil before and after N2 and CO2 flooding in five tight sandstone core samples at five different displacement pressures from 4.0 MPa to 24.0 MPa at 60°C. The fluid distribution and oil recovery rate under CO2 and N2 flooding were quantitatively evaluated at different pore scales under different displacement pressures.
The results revealed that the difference between N2 and CO2 flooding in the large pores was considerably higher than that in the small pores. However, the variation trend of the difference in oil recovery from small and large pores under N2 and CO2 flooding at different pressures was almost identical. Consequently, this variation was only slightly influenced by the pore radius and highly influenced by the displacement pressure. Additionally, before CO2 became miscible, the maximum difference in the recovery rate between N2 and CO2 flooding was observed when CO2 reached the supercritical state. After CO2 became miscible, the difference between N2 and CO2 recovery continued to increase with increasing pressure. Furthermore, for similar tight sandstone reservoirs, the total oil recovery rate under CO2 flooding was found to be always 10–20% higher than that under N2 flooding. Subsequently, the larger the pores, the better the oil recovery rate under CO2 flooding than that under N2 flooding. This study may provide significant guidance during field production.
Simulative Studies on the Control of Biofouling and Microbial Souring in the Wellbore of Injection Wells
Authors: De Paula Renato , Jones Chris , Armstrong Charles , Streets Matthew , Walker Leanne , Mohamud Muna , Eden Bob 
Published: June 2023

Abstract
This study evaluates the strategies to control microorganisms in the near wellbore area of water injection wells during secondary oil recovery. Biomass accumulation in the water injection wells can increase injection pressure and generate H2S. Nitrate injections can often overstimulate nitrate-reducer’s growth, increasing biofouling and souring downhole. Thus, control of microbes near wellbore must include the concomitant control of SRB activity and the reduction of the total microbial population. We evaluated strategies to reduce biofouling, increase injection flow and decrease H2S in simulated wellbore conditions. Sand-packed bioreactors containing soured biofilms were treated with different biocide formulations over 10 weeks. Volatile fatty acids, sulfide, and swept volume rates were used to evaluate the decrease in biofouling and microbial souring. Inlet and outlet biocide residuals were measured to determine loss of the chemistry during treatments. Genomic analysis (DNA Sequencing) was performed in fluids and core samples to determine shifts in the microbial population and to correlate the observed reduction in sulfide concentration and biofouling. The results showed that biocide shock treatments successfully mitigated the production of H2S in souring wellbore conditions and prevented rebounds and spikes of H2S between treatment cycles. Nonetheless, control of biofilms and biofouling was significantly more difficult to control under the same conditions, as the microbial populations quickly regrew after treatments, based on the increased consumption of volatile fatty acids after biocide treatment cessation. Biofouling and souring were not observed in control reactors that received biocide treatments since day one, highlighting the importance of a preventative approach to prevent chronic wellbore contamination. These results indicate that biofouling and H2S production are two phenomena that can be uncoupled as distinct problems during water injection. Additionally, our observations point to the importance of using different strategies to simultaneous control of souring and biofouling in near wellbore injection wells as a means to increase injectivity and sweet production. This paper will significantly expand the knowledge about water injection procedures and propose new strategies to control undesired microbial contamination in the near wellbore area. These strategies can help to prevent loss of production due to poor water injection and minimize the contamination of produced fluids by H2S gas.
Non-Ionic Surfactants as Boosters for FR Hydration in Brines
Authors: Kelley Allen , Fontenot Kristina , Becktold Christinna , Morgan Carla , Stanciu Cornell , Fernandez Jorge 
Published: June 2023

Abstract
A theoretical model of polyacrylamide polymers (PAM and PHPA) hydration dynamics is explored, with emphasis on the effect pf salinity on the hydration dynamics of traditional PAM and PHPA polymers. By understanding the interactions at a molecular level between the polymer and the solvent system it is expected that the polymer’s usability as a viscosifying agent can be extended into brackish and possibly produced water.
In this study, viscosity vs. time plots are used to find the hydration rates for PAM and PHPA emulsions in fresh water and various brines. Special brines were designed, including one with Fe(III) among components. The study is done by using common, commercial viscometers, utilizing an R1 B1 bob configuration with heated cup. The overall mixing shear generated is low and kept constant throughout the runs. The temperature and length of runs are also kept constant. This allows the determination of the rate limiting hydration step, maximum viscosity and the hydration rates of a wide variety of nonionic surfactants to be explored.
By comparing the PAM and PHPA hydration rates for the neat brine, tap water and brine with non-ionic surfactant it is shown that by choosing the correct nonionic surfactant the hydration rates can be increased by over 3500% from the brine solution and more than 10-50% from tap water. It is also shown that the maximum viscosity can be increased by over 700% from the brine solution and 27% from tap water. This trend was also shown to be true using Nano pure water. The results support the theoretical hydration dynamics we propose, showing the effect the nonionic surfactants have on the rate limiting hydration step and transitions between different hydration steps. The data is strong proof that by understanding the processes of polymer hydration, brackish and possibly produced water in a wide range of TDS can be used to successfully hydrate the polymer.
The novelty of this testing is that it provides further examples of how non-ionic surfactants can be used successfully to allow PAM and PHPA polymers to be hydrated in brine waters of various compositions with no damage to performance. Care was taken to utilize very common instrumentation and to develop simple and clear procedures for testing, to make the method easy and reliable to use by field labs that may not necessarily have state-of-the-art equipment available.
Towards Sustainable Oil Production: CO2 Footprint Assessment of EOR Surfactant-Based Processes
Authors: Marie Goavec , Mathieu Salaün , Mikel Morvan , Eric Delamaide , David Rousseau , Andres Negre 
Published: June 2023

Abstract
To meet energy demand while reducing CO2 emissions in a carbon constrained future, one of the key milestones of the roadmap proposed by the International Energy Agency is to stop new oil and gas field developments and extend instead existing fields’ lifetime. Waterflood and EOR recovery methods aiming at optimizing mature fields’ oil production thus appears as technologies of choice. Nonetheless, oil production by waterflood is energy and therefore carbon intensive, especially for oil fields exhibiting high water-cuts, due to produced water handling. Recent communications suggest that chemical EOR processes such as polymer flood reduce the CO2 emitted per barrel of produced oil compared to water flooding, as they reduce water cut and/or accelerate oil production. Few papers however assess the CO2 footprint of surfactant-based processes.
In this work, we aim to compare the carbon emissions of different chemical EOR scenarios including polymer, surfactant-polymer and alkaline-surfactant-polymer, with a reference waterflood scenario. We present an exergy-based methodology to estimate energy gains obtained from water-cut decrease while taking into account process efficiency, including oil production, water treatment required for chemical use and chemical production. The corresponding CO2 emission reduction is then estimated from these energy gains. This methodology was applied to two case studies available in the literature, the Mangala field polymer flood pilot and the Taber alkaline-surfactant-polymer flood. Necessary injection and production data were collected to extrapolate production water rate and WOR using Decline Curve Analysis.
Results show that implementing polymer or alkaline-surfactant-polymer flooding after waterflooding allows wells to reach higher oil production rates, up to twice as much. In addition, water-oil ratio is more than ten times reduced i.e. less produced water has to be handled while producing more oil. Thus, we show that for both of these fields oil production is less carbon intensive. Furthermore, we considered a hypothetical surfactant-polymer flood to compare to the Taber alkaline-surfactant-polymer flood. Water treatment as well as chemical production energy costs are reduced for the surfactant-polymer due to the absence of added alkali, which induces additional CO2 emission reduction.
This study highlights that chemical EOR, in particular polymer and/or surfactant-based processes stands as a potential solution to reduce the carbon footprint of oil recovery while maintaining the production required to sustain the world's energy consumption.
Improved Scale Prediction for High Calcium Containing Produced Brine at High Temperature and High Pressure Conditions
Authors: Shen Yu-Yi , Deng Guannan , Wang Xin , Kan Amy T. , Tomson Mason B. 
Published: June 2023

Abstract
Scale prevention is one of the most important problems in the oil and gas industry. Due to the more aggressive production behavior recently, there are more chances to encounter high temperature, high pressure, and high TDS conditions. This study focuses on improving the scale prediction in the condition of high temperature (up to 210°C), and TDS (total dissolved solids, over 300,000 mg/L) with calcium concentration up to 2.0 molality (m). A hydrothermal autoclave reactor was developed for solubility measurement. The solubility of anhydrite was measured in the CaCl2-NaCl-H2O solution with constant ionic strength of 4 m. Results shows that the ionic strength effect and the Ca-SO4 association would increase the anhydrite solubility while the common ion effect decreased the anhydrite solubility. The measured solubility data can develop the virial coefficient for the ion interaction of Ca2+ and SO42. This virial coefficient can then be applied in Pitzer models to improve the calculation for the saturation index of scale. Quantifying the Ca-SO4 interaction parameters can make a better prediction of mineral solubility with high calcium concentration. The results can also improve not only anhydrite but all of the sulfate scale predictions at high temperature with high TDS conditions. This study offers a reliable and efficient method to obtain solubility under high temperature conditions and expands the scale prediction of the production brine with high calcium concentration at higher temperature and pressure limits.
Clues from Dispersion and Deposition Based Test Methodologies to Solve the Asphaltene Jig-Saw Puzzle
Authors: Punase Abhishek , Burnett Will , Wylde Jonathan 
Published: June 2023

Abstract
Changing thermodynamic and compositional conditions of producing fields can cause decreased asphaltene stability and initiate aggregation, subsequent precipitation, and eventual deposition within flowlines. Usage of asphaltene inhibitors that prevent aggregation and tackle the problem right at the inception is widely preferred. However, such chemistries were observed to be counter-productive and led to higher asphaltene deposition in many cases. Thus, raising the question of what approach works best for assessing asphaltene stability: Dispersion or Deposition?
The focus of this study is to explore the relationship between the underlying working mechanism of dispersion and deposition-based test methods. Multiple crude oil samples produced from different regions of the world were evaluated using asphaltene inhibitor chemistries with optical transmittance, thermo- electric, and flow loop methods. Optical transmittance method evaluates sedimentation rate and cluster size distribution of asphaltene cluster within the test fluid medium. Thermoelectric method describes the dispersion state of asphaltenes within native crude oil. Flow loop setup assesses total mass deposited when the oil (blank or dosed) and precipitant mixture is flown through capillary tubes.
The results from these tests indicated that a fine balance between the dispersion and deposition mechanisms must be maintained as these may not respond linearly or in direct relationship at all conditions. It was seen that dispersing the asphaltene clusters too small may lead to high diffusional rate within the low flow shear regime and build up more deposit in depositional dominant test methods. Variation in treatment concentration (especially overtreatment) of an effective asphaltene inhibitor can result in lowering of cluster size to a range which in effect can cause more deposition. The overall assessment suggests that not having a holistic overlook at these test methods and following the standard process of giving specific focus on a singular approach, can mislead the asphaltene stability and inhibitor performance evaluation.
The key role of asphaltene cluster size as a bridge relating the dispersion and deposition-based test method is revealed in this paper. It is seen that there exists an effective range of cluster size within which the results from different test methods correlate well. Therefore, it is imperative that the asphaltene inhibitor development philosophy must include test screening methods focusing on each instability stage (precipitation, aggregation, and deposition) individually and combine the learnings to come up with the best recommendation.
Characterizing the Effect of Scale Inhibitors on Surfaces
Authors: Løge Isaac A. , Anabaraonye Benaiah U. , Fosbøl Philip L. 
Published: June 2023

Abstract
Inorganic scaling imposes a significant economic burden on the oil industry. Scale management protocols typically involve the use of chemical inhibitors. Most traditional methods of investigating scale formation and inhibitor performance do not provide insights into the exact mechanisms at play. However, understanding these mechanisms is critical to designing optimal mitigation interventions. We investigate BaSO4 scale formation in flow and batch experiments in the presence of a commercial inhibitor. For the first time, we apply sensitive texture parameters to characterize scale formation in the presence of chemical inhibitors. We analyzed effluent concentrations in the bulk phase using an inductively coupled plasma (ICP) technique, performed high-resolution X-ray CT scans of the surface deposits, and applied scanning electron microscopy (SEM) imaging. We used advanced image analysis to characterize how chemical inhibitors affect the overall deposition rate. We show the impact of time and inhibitor concentrations on corrosion processes.
Novel Modified Polycarboxylate Paraffin Inhibitor Blends Reduce C30+ Wax Deposits in South Texas
Authors: Xu Liang , Zhuk Iryna , Sirak Sofia 
Published: June 2023

Abstract
A typical challenge encountered during shale oil and condensate production in South Texas is severe wax deposition on fractured rock surface near the wellbore and flowlines from wellheads to separators, potentially reducing surface areas for oil and gas flow. Commonly used surfactant dispersants and wax inhibitors such as comb shaped polyacrylate/methacrylate (PAMA) and alpha-olefin modified maleic anhydride (OMAC) sometimes fall short and do not always address challenges associated with C30+ waxy crude oil and condensate. This is typically due to the mismatch of molecular weights and the incorrect ratio of polar and non-polar groups between the polymeric additive and the targeted wax species.
In this study, we present the findings of a new modified polycarboxylate and polyacrylate blend that provides a balanced approach of optimized non-polar and polar groups on the polymer backbone. Additionally, the inherent long polymer chains with a broad chain density distribution appear to interact well with C30+ waxy compounds, effectively lowering pour point, reducing wax appearance temperature (WAT) and suppressing wax deposition.
A gradual reduction of WATs in polymer treated waxy deposit was observed via DSC/CPM measurements when the polymer blends were varied with polyacrylate/methacrylate/modified carboxylate ratios. Cold finger tests were performed at selected temperature differentials that closely represented field conditions in order to demonstrate the efficacy of the optimized blend, in which deposits of C30+ waxy compounds were significantly eliminated.
It's commonly accepted that comb shaped polymers interact with wax crystals via incorporation and perturbation. The polymer blend presented here, with an optimized ratio of non-polar and polar groups, appear to enable a secondary mechanism that introduces a repulsive force between growing wax crystals, which is reminiscent of interfacial polarization of charged wax crystals under an external electric field. Through Zeta Potential, Cold Finger, Yield Stress, DSC, SARA and HTGC analysis, it was demonstrated that this additional interference rendered the comb shaped polymer blend much more effective, against other PAMAs, OMACs, and linear polymers such as ethylene vinyl acetate (EVA).