bluuebunny/crossref_metadata_2025_split huggingface dataset:
Examining MOOCs: A Comparative Study among Educational Technology Experts in Traditional and Open Universities
Authors: Cabrera Nati , Fernández Ferrer Maite 
Published: April 2017

<p class="3">The proliferation of Massive Open Online Courses (MOOCs) in recent years has generated much debate. MOOCs have been presented as technology-based educational practices, but many researchers question if this kind of open courses really respects some of the consolidated principles behind the education offered at universities. In light of this situation, consulting the teachers most closely tied to this type of course can provide an authoritative view of the issue and can allow the most important elements to be highlighted in order to carry out further research. Using a qualitative methodology based on an open questionnaire, this work presents the opinions and perceptions of teachers/lecturers in educational technology regarding these new courses key elements. These key elements are analysed through analysing its controversial definition, their pedagogical advantages and limitations, the functions of a tutor in a MOOC and their assessment (or accreditation). In addition, a comparison is made between the contributions of teachers from a traditional university with a face-to-face model and those from a distance university, which is based entirely on a virtual training offer and which has a greater possibility of coming into direct competition with these Massive Open Online Courses.</p>
Iliopsoas Impingement After Primary Total Hip Arthroplasty: Operative and Nonoperative Treatment Outcomes
Authors: Chalmers Brian P. , Sculco Peter K. , Sierra Rafael J. , Trousdale Robert T. , Berry Daniel J. 
Published: April 2017

Background:
A potential cause of persistent groin pain after total hip arthroplasty is impingement of the iliopsoas tendon. Treatment options include conservative management, tenotomy, and acetabular revision, but the literature, to our knowledge, has been limited to small case series on each technique. We present a series of patients with iliopsoas impingement after total hip arthroplasty and evaluate efficacy and risk factors for success or failure of each treatment strategy.

Methods:
Forty-nine patients treated at one institution for a diagnosis of iliopsoas impingement after primary total hip arthroplasty with hemispherical acetabular component and polyethylene bearing were retrospectively reviewed. Twenty-one patients underwent acetabular revision, 8 patients underwent tenotomy, and 20 patients had nonoperative management. The mean follow-up was 4 years. Anterior acetabular component prominence was measured on true lateral hip radiographs.

Results:
At the most recent follow-up, 10 patients (50%) in the nonoperative group had groin pain resolution compared with 22 patients (76%) in the operative group (p = 0.06). In patients with <8 mm of component prominence, tenotomy provided resolution of groin pain in 5 (100%) of 5 patients and a mean Harris hip score of 89 points. In patients with ≥8 mm of prominence, acetabular revision led to groin pain resolution in 12 (92%) of 13 patients compared with 1 (33%) of 3 patients treated with tenotomy (p = 0.07).

Conclusions:
Nonoperative management of iliopsoas impingement led to groin pain resolution in 50% of patients. In patients with minimal acetabular component prominence, iliopsoas release provided a high rate of success. Acetabular revision was more predictable for groin pain resolution in patients with ≥8 mm of anterior component prominence.

Level of Evidence:
Therapeutic Level III. See Instructions for Authors for a complete description of levels of evidence.
Technology Update: Electrokinetic Deposition of Asphaltenes Studied Under Dynamic Conditions
Authors: Kostarelos Konstantinos , Martin Clint , Tran Kyo , Moreno Jose , Hubik Aaron , Ayatolli Shahab 
Published: April 2017

Technology Update
Asphaltenes represent the heaviest fraction of crude oil, which are known to precipitate when the crude is added to aliphatic solvents such as n-pentane or n-heptane and yet remain soluble in light aromatic solvents such as benzene or toluene (Gawrys et al. 2006; Borton et al. 2010). They are characterized by highly complex structures that contain multiple aromatic rings and have a large hetero-atom content (e.g., nitrogen, oxygen, and sulfur) and metal content (e.g., vanadium and nickel) (Yarranton 2000; Hashmi and Firoozabadi 2012).
Asphaltenes tend to self-associate on a molecular level, depending on the composition, temperature, and pressure of the system. Precipitation of the particles out of solution results in flocculation, where they begin to deposit on hydrophobic surfaces such as metal pipes and surface equipment used for the production and transportation of crude oils (Khvostichenko and Andersen 2009). These tendencies result in reduced flow or complete blockage of producing wells and surface equipment, including pumps, pipelines, and separators.
Currently, the only methods of treatment are through the use of chemical dispersants and inhibitors, which increase the stability of asphaltenes to prevent deposition. Once asphaltene deposition has occurred, running a “pig” through the pipeline is often the method used to scrape the solids that accumulated on the walls of the pipe. It is known that asphaltene molecules can be polarized, gaining an electric charge by introducing an electrostatic field (Hashmi and Firoozabadi 2012; Khvostichenko and Andersen 2009; Khvostichenko and Andersen 2010; Hosseini et al. 2016). The polarity of the asphaltene particles is directly related to its hetero-atom content, with a higher hetero-atom content giving increased levels of polarity and a higher rate of aggregation (Hosseini et al. 2016).
Experimental Device
Our ultimate goal is to build a device (Fig. 1a) that would remove asphaltenes from crude oil near the point of production, using electrokinetics. Thus, a scaled-down device (Fig. 1b) was fabricated and tested using a model oil to prove the concept and study some of the parameters that would influence the design of a larger-scale device.
Drilling Operation Improvement in Overpressure Zone with Managed Pressure Drilling Technology in LFN Field
Authors: Fajar Rizki Arie , Irawan Cepi , Hasudungan Boyke 
Published: April 2017

Abstract
Drilling activity in Seram Island block is one of the most active in the Eastern Region of Indonesia. Drilling operator in the block has conducted drilling of 2 (two) exploration wells, where one of the well reached total depth to 19,230 ft. The well is one of the deepest onshore well in Indonesia. Both exploration wells have target to penetrate Manusela Formation as objective reservoir.
Actual drilling depth of the first exploration well LFN-1 in LFN field is 14,525 ft and the second well LFN-2 is 19,230 ft. The drilling effort in the LFN field faced many challenges, such as those experienced in LFN-1 well during drilling 8-1/2" hole section in Lower Nief formation whose lithology is limestone, partial loss occurred and in the consecutive formation of Kola with Shale whose lithology contained overpressure zone resulting in kick and well control effort has to be taken. This shows that the drilling operation in 8-1/2" hole section there is a narrow window of pressure regime between Pore Pressure (PP) and Fracture Pressure (FP) which is estimated to be ± 2 ppg. Thus drilling operator is required to use the latest method or technology to overcome the challenges and to finish drilling safely.
Efforts that were made to minimize operation problems in well LFN-1 have been analyzed and learned to be improvement on well LFN-2. One of the solutions selected was to use current well-known technology which is Manage Pressure Drilling (MPD) method on well LFN-2. The MPD is to be utilized on 8-1/2" hole section. The purpose of the application of the MPD method is to keep the Bottom Hole Pressure (BHP) to be constant in between Pore Pressure (PP) and Fracture Pressure (FP) thus minimizing the occurrence of losses and kick at the same time. The advantages of MPD usage are that we can make BHP constant during pipe connection so the hole does not allow kick and at the time of drilling, as it passes through the overpressure zone which is up to 17 ppg, the influx can be detected and anticipated quickly.
With the application of MPD method on LFN-2 well in 8-1/2" hole section, LFN-2 well could go according to plan and there was no problem as experienced before in well LFN-1. This is a good achievement in improving the performance of drilling at exploration wells with depth up to 19,230 ft.
HT Fracturing Fluid in Stimulating Saudi HTHP Gas Wells: Lab Results and Field Cases
Authors: Aldawsari M. A. , Al-Sagr A. M. , Al-Driweesh S. M. , Al-Shammari N. S. , Altammar A. H. , Atayev N. , Melo A. 
Published: April 2017

Abstract
The Carbonate Field, one of the world's largest oil and gas fields, consists of different reservoirs with different lithology where reservoir temperature ranges from 280 °F to 330 °F. Several high temperature, high pressure (HTHP) wells were hydraulically fractured in "Reservoir A," a gas bearing formation, in the Carbonate Field in Saudi Arabia. High temperature reservoirs present a challenge to successfully fracture because a novel fracturing fluid is necessary to sustain the high temperature.
Reservoir A is a sandstone gas-bearing reservoir associated with liquid condensate that in most cases requires hydraulic fracturing to enhance productivity and control sand production. Its high temperature and pressure creates technical and operational challenges.
The harsh formation environment requires a prolonged fluid stability to ensure stimulation effectiveness. Once the bottom-hole static temperature (BHST) is above 300 °F, borate-based crosslinked fracturing fluid can become unstable causing a rapid viscosity loss and eventually a poor proppant carrying capacity.
Metal-crosslinked fracturing fluids are well-known for high viscosity. Zirconates and Titanates are the main metal complexes of guar polymers. CarboxyMethylHydroxyPropyl Guar (CMHPG) crosslinked with Zirconium crosslinker is the most common fluid used in elevated bottom-hole applications as they develop excellent viscosity and proppant carrying capacity in these high temperature and pressure environments. Zirconate crosslinked fluids have been successfully pumped in wells where bottom-hole temperature exceeded 400 °F and resulted in a significant production increase (Stolyarov and Dean, 2011).
The technical stimulation approach in Reservoir A is to induce a wide and very conductive fracture to mitigate the pressure drop the producing fluid experiences as it reaches wellbore to prevent condensate banking. It is a vital to have a stable fluid to generate the right width to accept the higher proppant concentration.
This paper includes laboratory testing evaluation of fracturing fluid stability and breaker optimization. It will also show how the pressure falloff analysis was performed prior to the main frac to calibrate the fluid efficiency in the frac model and optimize fracture geometry. Post-treatment net pressure matching was conducted to predict the final fracture geometry and then nodal analysis was performed using the created fracture geometry and actual flowback data to further validate the incremental production increase after the treatment.
Safety Integrity Analysis of Topside Piping and Vessels Installed on Offshore Platform
Authors: Thakur Subodh L. 
Published: April 2017

Abstract
Offshore processing platform involves large volumes of hydrocarbons at high pressure and therefore these systems represent high risk to personnel, environment and asset.
The main objectives of this article are: ➢Understand well the new methodology of safety integrity analysis for piping and vessels under fire scenario➢Provide information on what is acceptable and unacceptable rupture➢Understand the methodology for fire depressurization calculations, rupture calculations and mitigation methods to achieve safe design based on actual project experience➢Comprehend inputs required by technical safety
In earlier method, the pressurized segment exposed to fire is depressurized to 6.9 barg or 50% of design pressure (whichever is lower) within 15 minutes. 15 minutes depressurization time had been a generalized time with set of parameters and might be too long and could lead to unacceptable rupture in the piping and vessel in some cases due to excessive stress generated due to fire.
The new method is an iterative process of designing a depressurization system with major focus on evaluating actual stress in the piping and vessels installed on topside. The new method actually checks the rupture time for a segment under fire and assesses if rupture is acceptable or not based on acceptance criteria from technical safety.
This paper discusses the actual calculation methodology for piping and vessel integrity analysis based on actual project experience and importance of safety input for the analysis.
This method actually determines if rupture is acceptable or not. Unacceptable rupture shall demand for some mitigation actions/design improvements suggested below in order to ensure overall topside safety in case of fire. ➢Increase or utilize flare system capacity➢Increase pipe wall thickness➢Selection of material with higher UTS values at elevated temperatures.➢Provide Passive fire protection (PFP) that will allow pipe or vessel to sustain for longer fire duration. (Focus shall be on fast depressurization and other options)
It is very important to check the integrity of entire piping and process equipment's on the process platform which results in reducing the risk of missile effect due to rupture that can cause fatalities or serious injuries and consequently reduces the risk of damage to neighboring pressurized hydrocarbon system further reducing the risk that may lead to major economic losses and environmental disasters.
The new methodology described in this paper is used in international projects and when applied ensures a step forward towards achieving safe and cost effective design which in turn shall care for human life, asset and environment which is top priority.
This method is published in new edition of international codes and standards.
Enabling New Field Development Projects for a Digital Future
Authors: Praveen Sam Samraj , Airani Avinash 
Published: April 2017

Abstract
The use of new digital technologies have become an imperative for oil & gas companies seeking to improve the way they do business. In this paper, a framework is presented for the strategic use of digital technologies for new field development projects. The benefits of introducing the right technology at the right time is identified across the life of field. There are six areas during field development where a digital strategy must be executed: subsurface analysis & modeling, drilling & completions, production operations, reliability & maintenance, procurement & supply chain management, and general business operations.
A case-study based approach is used based on large projects executed in recent the past where digital technologies were planned and included during early field development. The paper identifies the areas and points during field development to include different digital technologies where the business impact is maximum and capital and operational expenditure is minimum. This was done by identifying technologies across two areas: (a) technologies to enable the execution of the mega-project; and (b) technologies that form part of the facilities for operations during life of field. It was found to be optimum to link the digital strategy during the engineering and design stages, and during the issue of contracts for commissioning facilities. This allowed the field to build a digital ecosystem which will help them prepare for a digital future by enabling readiness for advancements in the areas of analytics, global mobility, and automation. Oil and gas companies obtain a chance to gain competitive advantage through digital infrastructure and software applications when applied at the right time during field development.
Reducing the Appraisal Uncertainty with Advanced Wireline Formation Testing Technology: A Case Study from the Gulf of Thailand
Authors: Lozet A. , Platt C. J. , Chanthanaphalin U. , Gok I.M. , Ridho M. , Doogue J. , Khunaworawet T. , Watana K. , Daungkaew S. , Duangprasert T. , Lerdsuwankij T. , Paramatikul R. , Shi Z. 
Published: April 2017

Abstract
The paper discusses an application of advanced wireline Formation Testing (FT) technology on an appraisal stage in order to improve an understanding of reservoir characteristics and to assist a field development plan. The advanced FT technology includes a focused sampling probe, a new 3D radial probe, and a new fluid analyser. Further information on tool functionality, real-time data interpretation, and acquisition result is described.
Fit-for-purpose wireline FT modules were deployed. The focused sampling probe delivered quicker clean-up for downhole fluid extraction. The new fluid analyser with improved algorithm and more sensors measured fluid properties at downhole condition and also quantified a contamination level prior to capturing a fluid sample. The new 3D radial probe (Saturn Probe), which has the largest flowing area among probe family, enabled fluid pumping and sampling at low mobility zones. An Interval Pressure Transient Test (IPTT) to obtain permeability and skin was also conducted with this new probe. The data acquisition was closely monitored and discussed on real-time.
Several wells have been drilled and data was successfully acquired at reasonable operation time. The focused sampling probe, with its unique design, met an objective of providing fast clean-up during pumping formation oil. This was indicated by a sudden change on the fluid analyser's Gas-Oil Ratio (GOR) and other parameters when the probe was in "split the flow" mode and focused. The sudden change was then followed by stable measurements of acquired properties indicating practically minimum contamination level has been achieved. Besides quantifying a contamination level, the new fluid analyser was also able to validate the fluid type which was derived from the pressure points. In addition, its viscosity sensor helped to understand viscosity variation among reservoirs which could not be done with a conventional fluid analyser. The new 3D radial probe maintained pressure drawdown while pumping at low mobility zones. Hence, sand failure that potentially deteriorates tool performance could be avoided. It also had shorter operation time than a conventional packer while conducting IPTT due to less inflating volume and tool storage. The IPTT results showed radial flow regime which was further analysed for permeability and open-hole skin.
In an appraisal stage, data acquisition is critical for field development plan and final investment decision. It definitely requires robust and advanced technology that is able to deliver conclusive answer in challenging environment. A case explained here shows how the advanced technology revealed a hydrocarbon potential and confirmed reservoir continuity.
Holistic Approach in Managing Challenges of Mature Offshore Carbonate Gas Fields with High CO2 and H2S Content in Sarawak Gas Operations, MALAYSIA
Authors: Abdul Aziz M. F. , Mithani A. H. 
Published: April 2017

Abstract
Natural gas produced from underground reservoirs varies in its composition depending on the type, depth, and location of the underground deposit and the geology of the area. Natural gas is usually considered sour if the hydrogen sulphide (H2S) content exceed a certain threshold. And the term acid gas is usually used if it contains acidic gases e.g. carbon dioxide (CO2). Natural gas is called sweet gas when it is relatively free of H2S and CO2. The contaminants in natural gas needs to be treated or maintained within a certain limit as per the required pipeline quality for exports and sales. In Sarawak Gas Operations, the contaminants is being managed by means of integrated gas blending.
Field B is one of the deepest platform-type carbonate gas reservoir in Central Luconia Province, offshore Sarawak with highest level of contaminants i.e. 40 mol% of CO2 and 2800 ppm of H2S. Sampling at more frequent interval of twice a year is implemented to monitor the trending of the contaminants level which will give perception on the effective blending management and maximum gas recovery. The strategy to produce as much as sour gas first while ample sweet gas is available to achieve maximum overall gas recovery is well understood.
Observation on the trending for more than 10 years suggest that the level of contaminants is increasing by time and the field is souring. This finding is supported by the understanding of CO2 and H2S solubility in water which is higher as compared to hydrocarbon gases. The suspected mechanism for the reservoir souring is the changes in CO2 and H2S solubility in water with pressure change.
This paper summarises the main issue of increasing contaminants level and effort to maximise gas recovery from the souring reservoir and discusses on the results from contaminants level trending and example from analogue field.
Optimizing Drilling and Completions in Overpressured Malleswaram Field by Integrating Geomechanics with Advance Acoustics Measurements
Authors: Reddy S. S. , Anjaneyulu J. V. , Lal Abhay Kumar , Rao E. J. , Ramakrishna C. H. , Talreja Rahul , Bahuguna Somesh , Zacharia Joseph , Chatterjee Chandreyi , Basu Jayanta 
Published: April 2017

Abstract
ONGC is working on fast-track development of Malleswaram field in Krishna-Godavari (KG) basin. Proven gas reserves are located in the in the late Cretaceous Nandigama formation which is located at a considerable depth. Exploration wells were drilled and overpressure of up to 1.8g/cc were encountered in Raghavapuram and Nandigama formations. Many drilling challenges related to overpressure were faced, including losses, tight hole, and stuck pipe. Apart from causing non-productive time (NPT), these events also increase the risk associated with drilling and completion of a well. Since, the development phase has just begun and geomechanics study was not incorporated in the exploration phase, there is enough scope to optimize drilling and reduce NPT. This study was conducted with an objective to optimize drilling and completion activities by integrating advanced acoustic and geochemical data for geomechanics based solution. This paper is focused on the new insight developed on the cause of overpressure and characterizing it. A detail analysis on stress direction and its variation with depth and among wells is also presented. In addition, wellbore stability models are also discussed to understand the requirement of appropriate drilling mud weights and casing policy in order to improve wellbore integrity, mitigate drilling risks, and ensure future drilling success. Minimum horizontal stress, breakdown gradient and rock elastic properties generated under the study are also used to generate completion quality flags to aid in identification of stress barriers within reservoir sand units of Nandigama formation.