bluuebunny/crossref_metadata_2025_split huggingface dataset:
PALHAÇOTERAPIA: ALTERAÇÃO DO PERFIL ÁLGICO E EMOCIONAL DE PACIENTES GERIÁTRICOS HOSPITALIZADOS
Authors: Rossi Isabela , Batigália Fernando , Júnior Randolfo Dos Santos 
Published: November 2016

Introdução: Os idosos ao serem internados em hospitais tornam-se suscetíveis ao desenvolvimento de transtornos mentais, necessitando portanto, de atividades que atuem de modo distrativo, promovendo bem-estar emocional e diminuição da sensação dolorosa. Nesse contexto, as atividades lúdicas, em especial a palhaçoterapia, apresentam-se como uma alternativa de baixo custo para minimizar essa problemática. Objetivos: Caracterizar a população idosa internada em um hospital terciário, avaliar a presença de sintomas ansiosos e depressivos nessa amostra, bem como se há melhora no estado emocional e diminuição da percepção de dor desses pacientes, após as intervenções dos “palhaços-doutores”. Casuística e Métodos: Participaram do estudo 35 idosos internados no Hospital de Base de São José do Rio Preto, sendo aplicados questionários (ficha de identificação, Inventário de Ansiedade Geriátrica, Escala de Depressão Geriátrica, escala unidirecional de dor, autoavaliação do estado emocional), por uma acadêmica previamente treinada, 1 hora antes e 1 hora após as intervenções lúdicas. Os dados obtidos foram posteriormente comparados e analisados de forma descritiva e qualiquatitativamente pelo teste estatístico de Wilcoxon. Resultados: Notou-se no perfil dos idosos analisados, prevalência de participantes do sexomasculino (57,5%), frequente histórico de internações anteriores (85,7%) e presença sintomas de ansiedade (40%). Em relaçãoàs alterações percebidas, antes e após as intervenções houve significante diminuição da sensação de dor (P=0,001) e melhorano estado emocional dos entrevistados, diminuindo as autoanalises de preocupação, ansiedade e tristeza, aumentando alegria eanimação. Conclusão: Os dados indicam que a palhaçoterapia é um método capaz de reduzir a sensação dolorosa, bem comopromover a melhoraria do estado emocional de pacientes idosos internados.
Comparative study of ultrasound guided supra-scapular nerve block versus intra-articular steroid injection in frozen shoulder
Authors: Sonune Swapnil P. , Gaur Anil K. , Gupta Shefali 
Published: November 2016

<p class="abstract"><strong>Background:</strong> Frozen shoulder is one of the most common musculoskeletal problems seen in orthopaedics. Many treatment modes are available however, it is difficult to treat and data on the comparative efficacy of various interventions are limited. Intra-articular corticosteroid injection (IASI) is a commonly used to treat frozen shoulder pain. Supra-scapular nerve block (SSNB) is also effective method to treat pain in chronic diseases that affect the shoulder. The present study was done to compare efficacy of ultrasound guided SSNB and IASI in management of painful frozen shoulder.</p><p class="abstract"><strong>Methods:</strong> 60 patients with painful frozen shoulder were divided in two groups, Group A received ultra-sound guided SSNB with 6 ml 0.5% Bupivacaine; Group B received IASI using 40 mg Triamcinolone. Outcome measures were shoulder ranges mainly lateral rotation and abduction, shoulder pain and disability index and visual analogue scale (VAS). Patients were followed-up on 2<sup>nd</sup> day, at 1<sup>st</sup>, 3<sup>rd</sup> and 6<sup>th</sup> week.<strong></strong></p><p class="abstract"><strong>Results:</strong> All baseline parameters improved significantly in both groups; however, on comparison Group A showed significant improvement in passive lateral rotation on 2<sup>nd</sup> day and 1<sup>st</sup> week follow up (P =0.038 and 0.040 respectively). VAS score showed significance at all follow-up in Group A, whereas, in Group B significance was seen after 1 week. On inter group comparison Group A shows significance on 2<sup>nd</sup> day (P =0.050), 1<sup>st</sup> week (P =0.042) and 3<sup>rd</sup> week (P =0.036).</p><strong>Conclusions:</strong>Both SSNB and IASI have efficacy in management of frozen shoulder. But supra-scapular nerve block is better than intra-articular injection and should be considered prior to steroid as it has early onset pain relief, early improvement in ranges, potentially lesser contraindications and side effects.<p> </p>
Carbon Nanotubes Generated from Polyphenyl Acetylene
Authors: Rajesh B. , Karthikeyan S. , Bonard J.-M. , Thampi K. Ravindranathan , Viswanathan B. 
Published: November 2016

<p>The carbonization of polyphenyl acetylene in alumina matrix yields uniform, cylindrical, monodisperse carbon nanotubes with outer diameter almost equal to pore diameter of the alumina membrane used. The<br />electrochemical characteristics reveal that the charge transfer at the composite electrode based on carbon nanotube might be higher compared to that of planar graphite, glassy carbon and composite electrode based on commercially available Vulcan XC72R carbon. Pt-Ru nanoparticles are highly dispersed inside the tube with an average particle size of 1.7 nm as revealed by HR-TEM images. </p>
Some Peculiarities of Creation of Stable Polyimide - Azo Chromophore System
Authors: Kudaikulova S.K. , Boiko G.I. , Shalabaeva I.I. , Zhubanov B.A. , Abadie M.J.M. 
Published: November 2016

<p>Azo dyes: methyl orange, methyl red, congo red have been suggested as doping agents for formulation of stable soluble azo dye - polyimide (PI) system according to guest-host scheme. The dyes were added to<br />the reactive mixture of monomers: dianhydrides of alicyclic tetracarboxylic acids and aromatic diamines. Polyimide synthesis was carried out by one step polycyclocondensation in protolytic media. Addition of azo dyes influences on the molecular weights of final PIs. In great extent they depend on the nature and concentration of doping agent. Investigation of dependence of reduced viscosity of PI on monomers concentration, duration and temperature of synthesis, concentration of doping agent. It has been determined that addition of dyes to the reaction mixture up to definite value rises molecular weights of PIs from 45-50 000 up to 320-330 000. The most efficient catalyst is congo red. However some functional groups of azo dyes disturb equimolarity of the reaction by interaction with one of main monomers. The colour of thus doped PIs is stable under processing and high temperatures. Stability of the azo dye - polyimide system depends on interaction of NLO agent with polyimide chain. It is suggested that congo red molecules can coordinate with carbonyl groups of polymer. PI films display solvatochromic properties.</p>
A new stepsize change technique for Adams methods
Authors: Calvo M. , Montijano J.I. , Rández L. 
Published: November 2016

Abstract
In this paper a new technique for stepsize changing in the numerical solution of Initial Value Problems for ODEs by means of Adams type methods is considered. The computational cost of the new technique is equivalent to those of the well known interpolation technique (IT). It is seen that the new technique has better stability properties than the IT and moreover, its leading error term is smaller. These facts imply that the new technique can outperform the IT.
ESP Reliability Lessons Learned From Three H2S Saudi Arabian Fields
Authors: Al-Khalifa Mohammed A. , Shepler Randall A. , Cox Robert L. , Alquwizani Saud A. 
Published: November 2016

Abstract
Previously, many Oil and Gas Production Companies elected not to develop hydrogen sulfide (H2S) producing fields, particularly offshore, in exchange for sweeter crude projects. A narrow number of H2S field developments resulted in a limited number of publications with empirical data on Electrical Submersible Pump (ESP) reliability producing in high H2S partial pressure offshore fields. This paper summarizes ESP reliability lessons learned and solutions implemented from more than 500 ESPs producing across three carbonate field wells characterized by high H2S/CO2 partial pressures, reservoir pressure and production rates; low bubble point pressure and low to mid-level water cut.
This paper utilizes ESP field observations and pull failure findings from over 200 Dismantle Inspection and Failure Analysis (DIFA) to confirm H2S behavior and root causes of electrical and mechanical failures within multiple ESP components. Moreover, H2S affects where ESPs were initially idle and exposed to H2S for one to two years either in static conditions or in naturally high rate flowing wells prior to commissioning are discussed. DIFA observations over a wide range of ESP runlife was instrumental in establishing the need for technologies to slow H2S movement across ESP components inclusive of a tandem seal section. Several motor seal sections have failed mechanically from H2S attack thereby requiring upgrade to high alloy metals, ceramic radial bearings and upgraded mechanical seals. Laboratory testing of failed conductor insulations retrieved during DIFA further exposed H2S methodology in creating electrical shorts. Systematic approaches were adopted to identify any unnecessary contributors such as power quality, operational practices or human error that may have facilitated H2S attack. Following the investigation and identification of unnecessary contributors; H2S scavengers were introduced into the seal section to slow H2S migration into the motor, lead sheathed motor lead extension (MLE) was upgraded with new H2S resistant insulation materials and design along with other new technologies that were trial tested to further improve ESP reliability and run life in H2S producing wells.
ESP component failure tracking and runlife statistics spanning an eleven year period are shared with the reader to validate the success of H2S resistant ESP component upgrades. Finally, methodology in calculating and measuring impact of varying degrees of H2S partial pressure and temperature from three high and two low H2S partial pressure ESP fields are provided.
Integrated Tubing for Both Steam Injection and Oil Production of Thermal Wells Based on ESP in Offshore Oilfield China
Authors: Han Xiaodong , Zhou Fayuan , Zhang Hua , Zhang Wei , Liu Hao , Wang Hongyu , Wang Qiuxia , Cui Junguo 
Published: November 2016

Abstract
Multi-component thermal fluid huff-and-puff pilot has been conducted in Bohai oilfield since 2008. Owing to the limitations of the temperature tolerance of some tools and facilities, the steam injection tubing and production tubing are applied separately during the development. That is, two work-over operations for tubing changes are required in each huff-and-puff cycle, which would increase the cost greatly and lower the development effect.
The objective of our present work is to design an integrated tubing with the functions of both steam injection and oil production to decrease the high cost caused by work-over of tubing change. First, we studied the artificial lift method that might be used for lift of fluid with temperature over 250°C e.g., electric submersible pump (ESP in short), gas lift, progressive cavity pump, and sucker-rod pump. Taking into account the degree of technology maturation, applicability in offshore oilfield and its temperature tolerance, the high-temperature electric submersible pump is selected for artificial lift of the integrated tubing.
On the basis of the ESP artificial lift, the integrated tubing with a Y-joint is designed. The steam injection string is connected with the main channel of the Y-joint and inserted into the production interval. The ESP is connected to the bypass of the Y-joint which could be used for fluid lifting during the production process. For the realization of the integrated tubing, high temperature tolerance tools such as the subsurface safety valve, and packer are developed. The maximum temperature-telorance value of the improved tools could meet the requirements of realizing the integrated tubing
In comparison with the previous techniques, application of the integrated tubing could greatly decrease the cost for thermal production and improve the economic benefit.
Increasing ESP Run Life Using a Combination of Reliable Abrasion-Resistant Pumps and 24/7 Real-Time Surveillance
Authors: Vidrianto Marda , Noviansyah Muhamad , Rajain Arun Kumar , Wang Feng Ming 
Published: November 2016

Abstract
In a field offshore Sumatra, several wells were experiencing pump failures because of loss of flow, sand erosion on pump stages, pump shaft rotation, broken shafts, and motor burnout. The remote offshore location of the wells was an additional hindrance, making it difficult to quickly respond to pump performance issues. This paper will show that the combination of abrasion-resistant pumps and accessibility and analysis of electric submersible pump (ESP) data are critical parameters for responsiveness and efficiency in troubleshooting.
The ESP reliability initiative began with well candidate selection to identify the most challenging wells with a known history of short run life primarily due to excessive sand and gas production. A new abrasion-resistant pump with enhanced compression design was installed in four wells as a pilot project. This count increased to 11 by Q2 2016. In addition, all these wells were put under 24/7 real-time surveillance to ensure that the pump performance issues were noticed immediately and acted upon much faster than in the manual troubleshooting process, which could take 2 to 3 days, at best.
A right combination of technical solution for pumps enabled better run life performance, and remote surveillance enabled faster troubleshooting and optimization of ESP peformance. These improvements are sustained through defined end-to-end workflows for performing root cause analysis of incidents performed jointly by the operators and ESP suppliers.
The Benefits of Introducing Intelligent Gas Lift Management to Create a Smart Field
Authors: Faux Stephen , Glenday Thomas 
Published: November 2016

Abstract
This paper will explore the benefits a smart gas lift field can offer in terms of operational efficiency, flexibility and production improvements, whilst focusing on health and safety improvements and risk reduction. Existing gas lift technology will be evaluated to give a summary of the operational aspects of the fundamental design and the methods used to control and change gas injection rates. The limited operational range of the existing gas lift technology will be compared against that of an intelligent gas lift system where these constraints are removed.
The increased flexibility of operation and field wide management aspect of a new intelligent gas lift system will highlight the limitations of the existing technology. It will be concluded that existing gas lift technology provides increased production of fluids when deployed in the correct fixed design conditions.
It will be observed that current gas lift technology does not have a particular focus on increased operational efficiencies on a field wide scale. It will also be observed that the current difficulties faced by the industry places scrutiny on operational efficiencies and the potential advantages new technologies offer. This provides opportunities to demonstrate how a step change in field wide management and the application of intelligent gas lift technologies can lead to better informed decision making and faster reaction speeds resulting in improved production efficiency.
The paper will discuss field wide design considerations that are only able to be made with a revolution in gas lift technology. The paper is aimed at inspiring the industry to reconsider conventional thinking.
Performance Analysis for Progressive Cavity Pump PCP Production Scenario in Sandy and Heavy Oil Wells
Authors: Alfaqih Muchammad R. , Ariwibowo Alexis , Juliana Christina T. 
Published: November 2016

Abstract
Sand problem and heavy oil has been the major constraint in producing oil in Sesanip Field Tarakan. The field has unconsolidated sand reservoir with grain size D50 of 200 – 300 µm and oil gravity of 18-22 deg API. Under those conditions, Progressive Cavity Pump (PCP) performance and lifetime has been a major constraint in producing the field. Five production scenario been implemented to acquire the most optimum lifting method.
Production scenario was divided into two phases. First phase was implementing PCP without sand control. This production scenario was used as a baseline for improvement. Second phase of the production scenario was to add sand control into the production system. Improvement between the two production scenario will be assessed using several criteria; lifetime, cumulative production, economic analysis. In the first phase, three production scenarios with PCP below perforation, PCP above perforation, and PCP with controlled production rate were implemented. Whereas in the second phase, results from downhole configuration of screen installed to pump intake, and installation of screen using seal-bore packer were compared with first phase results.
Comparison between five producing scenario were analyzed according to the criteria determined. Based on the first phase results, excessive sand production was evident when producing in optimum rate. In order to minimize sand production, production rate must be limited and therefore sacrificing artificial lift potential. Second phase gave two different results. PCP installation with sand screen installed to pump intake gave the lowest cumulative production, lowest revenue, and longest pay out time. Although sand screen was used, the lack of sealing above screen meant that sand was allowed to pile up in the annulus and eventually restricting influx. PCP with sand screen installation using seal-bore packer delivers optimum trade-off between lifetime, cumulative production and economic values. By applying this production method, sand production from the reservoir will naturally form sand-pack between perforation and sand screen. Although this sand-pack would decrease productivity index, but it compensates with higher lifetime. Based on recent well service activity, no sand pile was present inside screen or above seal-bore packer.
Rigless ESP Technology: Well Control and Completion Considerations
Authors: Bespalov E.. 
Published: November 2016

Abstract
Use of alternatively deployed electrical submersible pumping (AD ESP) systems requires review of the main principles behind completion architectures associated with traditional ESP technology. Completion architectures designed for rigless interventions need to take into account the main value proposition of the AD ESP technology, which is based on reduction of the deferred production and the ESP replacement costs, thus improving operating cash flow and reducing operating expenditure.
Accumulated operational experience of AD ESPs to date identified the main principles to be applied while looking at each specific application and considering the existing well control requirements and operating practices. Design of the completion architecture and the need for adjustment of the existing practices, while retaining focus on operational and personnel safety, has a vital impact on the operator's ability to realize an improved asset value from implementation of the AD ESPs as compared to the standard ESP technology.
The paper describes the technical aspects, technology development progress, and challenges of the AD ESP and highlights the main completion considerations that must be considered in designing a suitable completion architecture that would allow rigless replacements without a drilling rig or a hoist while adhering to applicable well control requirements.
The Research and Application of Carbon Fiber Rods in Deep Oil Wells of Xinjiang Oilfield, China
Authors: Zhao Ruidong , Zhang Xishun , Tao Zhen , Chen Shiwen , Zhang Xin , Li Gangyao , Oilfield Xinjiang , Huang Hongxing , Wang Hongfei , Guo Lei , Oilfield Jidong 
Published: November 2016

Abstract
As development of deep oil reservoir, more and more deep and ultra-deep wells, of which the chief lifting method is sucker-rod pumping system, are drilled. There often exist problems for systems above such as high load and low pumping efficiency. Because of low density and high intensity of carbon fiber rod, polished rod load can be decreased by using carbon fiber rod to increase safety factor. Meanwhile, since elastic modulus of carbon fiber rod is low, stroke loss will be increased by unreasonable lifting parameters. Test of carbon fiber rod was conducted in Xinjiang oil field in order to verify the feasibility of carbon fiber rod in deep oil wells and evaluate load shedding and energy saving effect. To lighten field test workload, a 3D rod mechanical model was built to simulate conditions of different production parameters. From the results of field test and simulation, it is indicated that carbon fiber rod owns better load shedding capacity and higher strength intensity; under the condition of deep wells, more stroke loss may be caused by carbon fiber composite rod. For some conditions, pumping efficiency is low, even worse, rod lock problems like gaslock may appear; reasonable combination of rod string and production parameters can improve the feasibility of carbon fiber rod.
Production Enhancement by Installation of Jet Pump in SSD in Pakistan Ghauri Oil Field
Authors: Kumar S.. , Kalwar S. A. , Farouque K.. , Qureshi S.. , Anjum Z. A. 
Published: November 2016

AbstractThis paper presents the first ever successful Sliding Sleeve Door (SSD) Jet Pump application in Ghauri oil field located in Jhelum, Pakistan. Ghauri is a single completed well flowed with 22 API gravity from the Sakessar Formation. Because the well is a solution gas drive reservoir, the initial production rate declined quickly. The use of jet pump was motivated by the need to revive the well without a work-over.Based on initial testing data, jet pump was selected as a preferred artificial lift method. SSD was installed as a part of initial completion. The downhole jet pump was designed per the SSD dimensions. The pump was operated to enhance/ restore the production of well. During operations, real-time monitoring was conducted to optimize the parameters of the pump, such as the nozzle/throat combination or horsepower. In addition, the life of the jet pump was calculated in relation to the economic limits of the production.Based on the results, the jet pump was found to be the most economical and cost-effective artificial-lift method for Ghauri. SSD jet pump deployment achieved the expected performance and reliability. It has allowed the operator to save the cost of a workover. The cumulative production with jet lift is twice the cumulative production using natural energy. When the well production declined, the jet pump was easily re-optimized by using slickline to pull the pump and change the nozzle and/or throat. The rest of the pump was unchanged to keep the CAPEX at low. In addition, further production of 200,000 BBLS is expected through the jet pump.