bluuebunny/crossref_metadata_2025_split huggingface dataset:
Current Helicopter Underwater Egress Knowledge: Are we Prepared for the Next Ditching?
Authors: Taber Michael J. 
Published: September 2014

Abstract
The purpose of this paper is to highlight the current helicopter underwater egress knowledge available from various online sources. Publicly available online sources were used as a way of ensuring that anyone with Internet access would be able use the information as opposed to a private library of technical documents or exclusive access to particular journal databases. Given that more than 30 years of underwater egress training has been completed, it was expected that the majority of the papers/reports available would be directed at training methodologies, ditching statistics, and factors affecting survival. A total of 18,862 entries were identified from six different search engines. Of the nearly 19,000 items, only 112 (1%) were considered relevant. From the directed search, it appears that a considerable amount of work has been carried out to identify the factors affecting egress as well as in the area of accident investigation. Surprisingly however, only 14% of the 112 selected documents address aspects of underwater egress training and just 2% directly address the retention of skills. A total of 10 (9%) consider ditching statistics, and 49 (44%) address the factors affecting egress. Based on the findings from this focused examination of available underwater egress literature, it is clear that further work needs to be directed toward how to best prepare the global offshore workforce for a ditching/water impact.
Using an Ecosystem Approach to Manage Environmental Risk in The Al Shaheen Oil Field off the Coast of Qatar
Authors: Bach Steffen S. , Ahmed Ali A. , Lawson William A. , Reeves Catherine E. , Eegholm Mads E. , Lueders Sebastian von , Al-Jeidah Mohammed , Nour El-Din Nehad M. , Al-Hajri Salma H. , Al-Emadi Ameera M. , Al Malki Ameena Abdullha , Robinson David 
Published: September 2014

Abstract
The Al Shaheen oil field is located approximately 80 km north-east off the coast of Qatar in the Arabian Gulf. It is the largest offshore oil field in Qatar and it is operated by Maersk Oil on behalf of its partner Qatar Petroleum. The Al Shaheen area is a highly productive marine environment due to a combination of complex nutrient rich currents and high temperatures. The diverse marine ecosystem is exemplified by one of the world's largest aggregations of whale sharks (Rhincodon typus) that return to this area every summer. The whale shark is listed as vulnerable on the IUCN Red List of Threatened Species and is the largest fish in the world. Having to operate in an area that hosts such a unique natural event poses a challenge to the parties involved but after years of dedicated research the secret behind the annual aggregation of the whale sharks in the Al Shaheen field is now better understood. The knowledge that has been gleaned is currently being used to help prevent significant disturbance to these majestic species and at the same time, maintain an efficient operation. Seismic operations have been scheduled for periods outside of the known aggregation season, and vessel traffic has been restricted in certain areas of the field. These initiatives have revealed that cost effective environmental risk management is achieved by gaining the best possible understanding of the ecosystem that is being impacted. Unless substantial published information is available for the area of concern this will most often require dedicated and continued research efforts. The reward in taking an "Ecosystem Approach", however, is an opportunity to establish collaboration between the industry, regulators and academia, resulting in effective and well-documented mitigation measures.
Real-Time Transparency Financial Simulation
Authors: Christou Chariton 
Published: September 2014

Abstract
Diagnose the conflicts in production sharing contracts between oil companies and government is of key importance in oil & gas industry. Among the principal creation of such problems are the recoverable costs. However, this is a property that is difficult to observe. On the other hand, transparency from the production of a field is a crucial point to the audit. If the government has a clear view of the production of a field such conflicts could be avoided.
The research work presented herein demonstrates the design and the development of a real time financial simulation, using basic principles of the industry aims to contribute toward this issue. The scope of the study is to give to the government a clear view of the economics from a particular field. At any time both parties could have a view of the production, the income, the costs and the taxes. Such simulation could help companies and governments to cooperate and bring a transparency to the industry; which appears not to be in our days. In addition it will provide a clear view of the economic aspect of the oil price according to the production and it costs only.
The method proposed exploits the flow meter tools in a real based approach to give the production of a field that it's coming from the pipeline. It interacts with the main console and the principles that have been inserted so it will give to the user the appropriate information. The main input is that and some other inputs are the material costs, the labor and the equipment, which are inserted automatically also.
The simulation was validated with a real case scenario and the production of a field to help us understand the calculations and the results. The validation was based on known profits, costs, taxes, etc. and shown results that there was close to those who where simulated. The PSC that has been simulated is the Cyprus government contract for its EEZ.
As for the application of this simulation, it can be very useful for the governments to check their sharing percentages and bring a transparency to the industry but also to the companies which can have a clear view of the economics of a field at any time.
The goal of this work is to bring a transparency to the industry, help governments understand the oil pricing of the companies, help the real time decision of the user using the economics of the production.
Designing Behaviours. An Innovative Approach to Driving Organisational Safety Culture.
Authors: Matkin Darren , Scotti Davide 
Published: September 2014

Abstract
Saipem has worked tirelessly since 2006 to deploy its safety leadership program, both shaking the mind and hitting the heart of people with a particular focus toward ‘Leading Behaviours’, going beyond traditional communications to propagate safety culture.
Five simple and transferable ‘non-negotiable’ behaviours, carefully developed by a HSE and Operational Management Workgroup, were injected into the workplace over a nine-month period for embedment into the DNA of everyday actions and decisions, disrupting a cycle of unsafe behaviour.
Following the CEO's campaign launch companywide, Management and Line-Supervisors cascaded the behaviours through high influence events to their Workforce; supported by multimedia communications and incorporating ‘peer-conformity’ mechanisms of story-telling, widely evidencing behaviours translated into action by employees, encouraging others to follow and conform.
The 9-month strategy releases a behaviour every six-weeks, maintaining long-term focus which allows practice of each behaviour before the next is released. The campaign concludes with a twenty-minute hard-hitting film which follows the life of a Saipem employee, visibly demonstrating how the Leading Behaviours can be interwoven into working and home life in simple terms.
This innovative emotional and behavioural based approach has paid dividends, reflected in the accident frequency reduction of over 50%, and increased proactive safety observations by 70%.
Humans are resistant to change but highly susceptible to peer-to-peer influence, easily adapting to behavioural change when those around are involved in the process.
In order to accelerate the cultural development an innovative and inspiring campaign ‘Leading Behaviours’ was introduced during 2011, focusing on visible behavioural change, peer-to-peer conformity, and incorporated a bottom-up and top-down strategy, actively engaging the workforce.
This methodology along with management passion and commitment and workforce engagement is truly industry excellence which could easily be replicated, and will be of interest to managers aiming for zero-accidents within multicultural contexts.
Laboratory Evaluation of Gas-Injection EOR for the Heavy-Oil Reservoirs in Suriname
Authors: Bhoendie K. S. , Moe Soe Let K. P. , Li T.. , Zitha P. L. 
Published: September 2014

Abstract
Staatsolie conducted several screening studies in the past decade to explore the potential of enhanced oil recovery (EOR) for its heavy oil fields in Suriname. The latest screening study was performed in 2011. It indicated that combined gas and water injection could be a highly efficient method to extend the life of the fields beyond primary recovery. To validate this conclusion further, an area of the Tambaredjo heavy oil field was selected for a feasibility study comprising laboratory tests and field scale reservoir simulation studies. This paper presents a series of core-flood tests done to evaluate the potential of several CO2 and N2 injection schemes and to gather data for the further numerical simulations. CO2, N2, and brine were injected either (1) on continuous mode or (2) in a water-alternating-gas (WAG) mode into Bentheimer sandstone cores previously saturated with Tambaredjo heavy oil, having a viscosity in the range of 650 to 1,100 cP and a density ranging from 16 to 17 °API. The injection strategies tested resulted in substantial incremental oil recovery (relative to OIIP), but values hereof varied from strategy to strategy. The core-flood test with continuous CO2 injection following extensive water flooding resulted in an incremental recovery of 31.1% over tertiary CO2 flooding stage. Continuous N2 and CO2 injection in a secondary mode resulted in incremental recoveries of respectively 14.8% and 24.5% over secondary drainage stage. Subsequent long water slugs resulted in both cases in further increase of the recovery by 48.1% and 29.2%. N2 and CO2 WAG with WAG ratios and slug sizes chosen based on optimized reservoir simulations resulted in similar recovery factors. Overall recoveries for five schemes used in core-floods were in the range of 49.6 to 65.9%. The paper discusses the mechanism responsible for the oil displacement for each injection strategy and presents how the core-flood tests can be used to model gas injection for a sector of the heavy oil reservoirs of Suriname.
Integration of NMR and Conventional Logs to Evaluate High-Permeability Heavy Oil Reservoirs
Authors: Nandlal Soerin , Graanoogst Fabian , Oedietram Jasvant , Quintavalla Claudio 
Published: September 2014

Abstract
Heavy oil refers to oils having an API gravity lower than 20° and viscosity at formation conditions above 100 centipoise (cp). These hydrocarbons generally pose challenging production problems and are marketed at a discounted price. However, the combination of improved technology and higher oil prices make the exploitation of heavy-oil deposits more economically feasible. Besides the quantity of production and processing problems associated with heavy oils, evaluating petrophysical properties from nuclear magnetic resonance (NMR) logging measurements can be problematic because of a number of issues, such as heavy oil NMR responses are similar to signals from capillary-bound water.
Additionally, heavy-oil chemistry can be conducive to a wettability alteration that can lead to a misinterpretation of water content from conventional and NMR logs. These phenomena make it difficult to quantify and type fluid volumes in heavy-oil reservoirs from NMR measurements alone.
NMR logging instruments sometimes do not fully capture heavy-oil signals because they operate at inter-echo spacings that make them unable to adequately sample important rapid decay components when viscosity exceeds ~1000 cp. This situation causes the indicated NMR porosity to be somewhat small, as though the reservoir fluid had a hydrogen index (HI) smaller than one, as occurs in gas reservoirs.
These factors make it necessary to apply advanced interpretation methods to find indications of altered wettability and evaluate petrophysical quantities, such as fluid volumes, permeability, and apparent in-situ oil viscosity.
The method consists of combining NMR and conventional wireline logs to measure the signal loss and estimate the oil's viscosity where the in-situ viscosity is larger than a few hundred cp. Additional combinations with conventional logs can be formed with NMR diffusion measurements to infer movable and capillary-bound water volumes. These volumes can then be used to refine interpretations of resistivity logs, indicate altered wettability, and provide an improved estimate of permeability in heavy-oil reservoirs.
This paper shows the validation of this method implemented in over 20 wells in the Suriname-Guyana basin. The average well depth is approximately 1,000 ft, bottomhole temperature (BHT) is ~100°F, and gravity is in the range of 10 to 20 API. The results are validated with production data.
Potential of Steam Solvent Hybrid Processes in Llanos Basin, Colombia
Authors: Andarcia L.. , Bermudez J.. , Reyes Y.. , Caycedo H.. , Suarez A.. 
Published: September 2014

AbstractEastern Llanos in Colombia is a heavy oil prolific basin. Reservoirs in this area generally exhibit water intrusion and extensive transition zones which its origin is probably explained by a combination of lithology variation and a week density contrast in between the reservoir water and oil. If oil viscosity at reservoir temperature is low enough to allow primary production; it is feasible to develop heavy oil fields using horizontal wells and high volume lift pumps. However, operators have to prepare to treat and dispose large volumes of produced water. Other reservoirs with higher oil viscosity require an enhance oil recovery (EOR) processes to pursuit a commercial development. Among the recovery methods applied to heavy oil reservoirs, the most popular is steam injection in its different schemes. Nevertheless, in high initial water saturation environments the thermal efficiency of the steam is under concern. Other EOR options include but not limited to: polymer injection, Alkaline Surfactant and Polymer “ASP”, “In situ Combustion”, Single Well SAGD, SAGD, VAPEX, Solvent Injections and Steam Solvent Hybrid Processes. In hybrid processes an amount of solvent is added to the steam. It is thought that the efficiency of the thermal recovery can be improved by such solvent fraction. It is expected that the presence of solvent helps reducing the cumulative Steam to Oil Ratio (SOR), therefore the overall economic of the recovery project. The amount and kind of solvent are important factors to investigate for any particular reservoir. The production potential under steam hybrid process has been studied in this work with focus on heavy and extra heavy oil reservoirs exhibiting high initial water saturation in llanos basin.It has been found that this process looks very promising to overcome the difficult task of producing very viscous oils in presence of mobile water. Numerical evaluations and laboratory displacement test conducted with reservoir fluids and rocks gathered from llanos basin heavy oil reservoirs; have shown a clear improvement on displacement efficiency in hybrid steam-solvent injection with regard to pure steam injection.
Factors Affecting SAGD Performance in Dipped Bed Extra Heavy Oil Reservoirs
Authors: Andarcia L.. , Bermudez J.. , Reyes Y.. , Caycedo H.. , Suarez A.. 
Published: September 2014

Abstract
In reservoirs with certain dip, the steam chamber advances different than in conventional SAGD projects. Since the horizontal permeability is normally higher than vertical permeability and because reservoir pressure is lower toward up-dip; an early lateral growth of the steam chamber should be promoted to the uppermost reservoir position. If horizontal permeability controls the gravity drainage instead of vertical permeability, it is thought that a good gravity drainage process in dipped reservoirs could be achieved, even in cases were vertical transmissibility is poor. However, if there is mobile water within the reservoir, then the steam easily flows up-dip and away from the producer well diminishing the hot oil draining to the producer and affecting the SAGD well's performance.
The factors affecting SAGD efficiency in a dipped-bed extra heavy oil reservoir (6.5°API) located in southern llanos Colombia have been analyzed. An important extra heavy oil accumulation toward the outcrop of main production sands was encountered. The reservoir temperature is low (100°F) so bitumen viscosity is high (&gt;100.000cp). In addition, oil saturation could be lower than is the standard for commercial projects in some areas.
A reservoir characterization was done using data from 18 wells. Information from basic and special logs, routine and special core analyses as well as displacement tests was used to build a robust numerical model. Several numerical simulations were run to address the performance of SAGD under such conditions. Particularly, the amount of mobile water and dip, play a major role in SAGD efficiency since the steam chamber behaves accordingly to both parameters. Numerical simulations done in this work have shown that SAGD thermal efficiency in dipped bed reservoirs is dramatically affected by energy losses toward the uppermost reservoir position since the steam tends to flow up dip far from producer wells. This effect is amplified when mobile water is within the porous medium.
Different strategies to improve SAGD efficiency were explored by numerical simulation. Well configuration was changed from parallel to staggered; electromagnetic heating was evaluated as well as hybrid processes. Hybrid processes could certainly open doors for economic development of highly viscous heavy oil reservoirs with mobile water saturation.
The Role of Asphaltenes in Emulsion Formation for Steam Assisted Gravity Drainage (SAGD) and Expanding Solvent - SAGD (ES-SAGD)
Authors: Kar Taniya , Williamson Matthew , Hascakir Berna 
Published: September 2014

AbstractSteam Assisted Gravity Drainage (SAGD) and Expanding Solvent SAGD (ES-SAGD) have previously been compared and ES-SAGD has shown improved oil recovery with lower energy and water requirements and significant oil upgrading. However, solvent selection is the key factor which determines the performance of ES-SAGD due to the asphaltene-solvent interaction. The change in asphaltene stability with the solvent type can have several drawbacks during ES-SAGD. Stable emulsion formation is one of these problems which have not been investigated thoroughly for ES-SAGD. In this study, we characterized both water-in-oil and oil-in-water type of emulsions originating from SAGD, SAGD with n-hexane and SAGD with n-hexane and toluene mixture experiments. These three experiments were conducted on 8.65 °API Canadian bitumen with 34.3 wt% asphaltene content. Structural changes in produced oil, produced water, and spent rock samples were analyzed with Fourier Transform Infrared (FTIR) spectroscopy. Emulsions in produced oil and water samples were determined with microscopic images. The differences in emulsions were interpreted with the wettability change determined on spent rock samples. Moreover, the asphaltene fraction of produced oil samples is further analyzed with FTIR and zeta potential measurements. For produced oil, the greatest asphaltene content with more severe emulsion formations were detected on the sample originating from SAGD. In terms of stability, because the asphaltenes originating from both ES-SAGD experiments have higher zeta potential values, lower emulsion stability has been observed for the produced oil originating from ES-SAGD. In summary, the role of asphaltenes on emulsion formation has been studied for SAGD and ES-SAGD for bitumen extraction. ES-SAGD with asphaltene soluble solvents leads to the formation of less stable emulsions.
First Extra-Heavy-Oil Development in Caguan-Putumayo Basin, Colombia, Capella Field
Authors: Valbuena Amaris Oscar H. , Bernal Maria E. , Ramón Juan C. , Xiuxia Tian 
Published: September 2014

Abstract
Capella field is the first extraheavy oil development in the North part of the Caguan-Putumayo basin in Colombia. In addition to the normal reservoirs complexities of any new field, by this condition, no analogous reservoirs and developments are available, putting and additional challenge on the field development.
The field has two main development targets, both clastic, one conventional high porosity-permeability reservoir (Mirador Formation, main objective) and one naturally fractured; both with extraheavy oil as reservoir fluid, 9 API degrees, with viscosities in the range of 2500 - 4000 centipoises at reservoir conditions.
It was defined that the development with horizontal wells, complemented with vertical wells is the best alternative for the field, but even the efficiency of this alternative, the primary expected recovery factor will be below 10%, caused mainly by the high viscosity of the oil. Best identified alternatives to increase the recovery factor were thermal stimulation with steam, both cyclic and continuous, being already some pilots done at the field.
New cyclic steam stimualtion (CSS) pilots are being defined to be implemented on year 2015, having as main goal the definition of best conditions to implement the CSS around the field and the efficiency of the methodology on different areas and/or reservoirs.
This paper presents geological characteristics of the field, production mechanism and behavior, principal development conditionings, main uncertainties and details of the field development strategy.
Can SAGD Be Exported? Potential Challenges
Authors: Alvarez J. M. , Moreno R.. , Sawatzky R. P. 
Published: September 2014

Abstract
In spite of its relative youthfulness as a commercial IOR technology, SAGD has had a profound impact on the development of the oil sands in northern Alberta and consequently on Alberta's economy. The path from a concept as articulated and developed by an individual research engineer, Roger Butler, to a commercial recovery technology for exploiting Alberta's oil sands has at times been a rocky one. More than 30 years of applied research and development at both the laboratory scale and the field scale by a community of researchers has been necessary to advance the technology to its current state of development. The SAGD technology has faced countless challenges since its origin. The public literature is replete with examples of challenges it has faced in the past, and others that are predicted to be just over the horizon. For example, more research and development will be required to expand SAGD to more challenging areas of the Athabasca region. The challenges will include reservoirs that have shale barriers, those that have bottom/top water zones, and those that are marginally too thin for conventional SAGD. Variants of SAGD, such as fast-SAGD, X-SAGD, and ES-SAGD, were conceived in response to the need to expand SAGD beyond the sweet spots in Alberta's oil sands where the original technology was demonstrated. Lessons learned from the application of SAGD technology in Alberta's oil sands may be useful to international producers from around the world that are interested in trying to adopt SAGD for use in their reservoirs. This paper will discuss potential challenges that may be encountered in the implementation of SAGD as the technology is migrated from its birthplace in the Athabasca oil sands to heavy oil and bitumen reservoirs around the world.