bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Training Delivery to Adapt to Millennial Entering the Workforce
Authors: Audrey Beryl , Florez Fabian , Kartoatmodjo Gayatri 
Published: November 2020

Abstract
Despite the downturn in oil and gas industry, the recruitment of young engineers continues to ensure the succession of workforce pipeline. The need of building their competency is critical and hence a systematic training program is required with the emphasis of agility to adapt to any business condition leveraging with the latest technology.
One of the most important skillsets to any graduating engineers and scientists entering the oil & gas industry is to understand fluid flow from the reservoir up to the sales point, starting from a basic well productivity driven by reservoir characterization to surface facilities equipment functionality and specifications. Digital technology has been one of the main enablers of the link to efficiently develop an oil/gas field. An interactive training program is built to combine the theory and practical in a modular format. The program is designed to deliver a practical graduate engineer within 30 to 36 months of hire. The program consists of combination of on the job (OJT), web-based training (WBT), classroom and hands on practical training. One of the main modules is designed to mimic an oil field condition using state of the art digital technology to simulate both subsurface and surface condition. This module is designed to enable engineers to learn actual data, associated with field problems that lead to decision making process in the field.
The overall training experience allows the use of a real facility equipment with minimum HSE risk. The simultaneous reservoir/production model proved that is powerful exposure to build quick basic to intermediate production, reservoir and operation competencies in a controlled training environment.
CO2 – Green Refrigeration for FPSOs
Authors: Adamson Ben 
Published: November 2020

Abstract
FPSOs usually require refrigeration, for removal of condensates and/or water before export of produced gas, or for treatment of gas to be used on board as fuel gas. This paper describes on-board refrigeration using a new combination of different concepts, none of which individually are new, to deliver refrigeration for FPSOs with environmental, cost, space and weight advantages.
Usually, FPSO owners specify a non-flammable refrigerant, and most current applications use R-134a refrigerant. However, R-134a is a hydrofluorocarbon with high global warming potential (GWP = 1300). These high-GWP refrigerants are being phased out under the 2016 Kigali amendment to the Montreal protocol, and are already banned for new applications in many European countries. Low-GWP alternatives to R-134a include hydrocarbons such as propane (GWP = 3), ammonia (GWP = 0), hydrofluoroolefines (HFOs) and CO2 (GWP = 1). HFOs are new synthetic refrigerants with GWP generally &lt;150, but are flammable, though less flammable than propane.
CO2 was widely used as a refrigerant up to the 1930s, particularly in marine applications, but was superseded by early synthetic refrigerants such as R-12 and R-22, which were then phased out in the 1990s after discovery of ozone depletion effects. CO2 is limited in air-cooled applications at high ambient temperature conditions such as tropical climates, due to the high-pressure side of the system becoming supercritical, leading to high operating pressure and low efficiency. However, FPSOs mainly operate in deep water, and even where surface water temperature is high, say +30 deg.C as in the tropics, cold water below +20 deg.C, can be found at depths of 100-200 m, even at the equator. Use of cold seawater via deep inlet risers is already used for some other FPSO applications, and if used for cooling in CO2 refrigeration systems, the system can operate at subcritical conditions, power becomes competitive and an optimised CO2 refrigeration system can have lower power, smaller footprint and lower weight, compared to a similar optimised R-134a refrigeration system.
CO2 is now a viable refrigerant for FPSOs, with environmental, cost, weight and operational advantages over R-134a. Using CO2 as above is a new combination of known concepts, none of which individually are new, to achieve a new and better refrigeration outcome specifically for FPSOs. It is not a proprietary technology of any company.
Optimizing Production from Marginal and Challenging Prospects to Unlock Field Potential: Success Cases in the Jasmine Field, Gulf of Thailand
Authors: Yusuf Mukminin , Prasongtham Pattarapong , Limniyakul Theeranun , Nuada I Nengah , Kulchanyavivat Sawin , Laoroongroj Ajana , Dachanuwattana Silpakorn , Watcharanantakul Rattana 
Published: November 2020

Abstract
The development of marginal volumes in the Jasmine field is part of Mubadala Petroleum's overall strategy to extend the field's life. This development is accomplished by progressively exploiting increasingly challenging prospects. This paper highlights two case studies to illustrate how Mubadala Petroleum has successfully developed marginal prospects to unlock the Jasmine field's remaining potential.
Prospect identification begins with integrated subsurface studies focusing on contingent resources. Several studies were conducted to determine the right technology to mature these marginal prospects. These prospects often involve the requirement to drill Extended Reach Drilling (ERD) wells. This is due to the fact that some platforms are slot constrained, such that wells cannot always be drilled from the nearest platform.
One of Mubadala Petroleum's solutions was to drill a horizontal well with a completion that uses an Autonomous Inflow Control Device (AICD) to optimize and enhance oil production. This combination of AICD and ERD horizontal wells has proven successful in the Jasmine field's continuing development.
Two wells in this case studies were drilled during the 2018 and 2019 drilling campaigns, illustrate how marginal volumes are developed in the Jasmine field, with each case having unique objectives and challenges.
In 2018, one horizontal well was drilled, with an aim to enhance recovery efficiency in the viscous oil reservoir. The well was drilled close to the top reservoir, AICD devices were installed in conjunction with a sand screen to delay water breakthrough, and the well has been in production for two years. The overall strategy was effective in delaying water breakthrough.
In 2019, a horizontal well was drilled to develop a relatively small 14ft oil rim below a thick gas cap reservoir. This well was the longest ERD well in the Gulf of Thailand. The well was also successfully drilled and geosteered at 4-5 ft TVD below the gas cap. AICD's were installed to balance the gas cap expansion and aquifer support to optimize oil production. The well has produced at a stable oil rate of 500-600 bbls per day with minimal gas and water production, up to the present date, confirming the validity of AICD technology in reducing the production of unwanted fluids.
The AICD has been shown to play a significant role in optimizing production in reservoirs with small oil rims and thick gas caps. AICD completions also help to enhance production recovery from viscous oil reservoirs. Moreover, ERD drilling has improved the feasibility of several remote prospects and minimized the slot availability constraint in the Jasmine field.
Hybrid Workflow Integration for Deep Reading Measurements and Geomechanics Process Enhanced Drilling Performance
Authors: Javay Alexandre , Imam Santoso Gagok , Syamsudhuha Aldia , Amer Ali Syed , Ahmed Sajjad 
Published: November 2020

Abstract
In a deep gas drilling project, landing the 7" liner at the top of a thin carbonate layer is critical to ensure ease of drilling and maximize reservoir exposure. Real-time multi-layer bed boundary detection technology was utilized to enhance top of reservoir detection certainty. This approach reduces the hard caprock interval in the next section which potentially causes wellbore instability and downhole tools failure, allowing drilling long reservoir section with minimum BHA runs.
Picking the top of caprock using conventional approach was challenging due to the lack of control points and the absence of distinct markers to distinguish the reservoir from the caprock. The variations in formation thickness and structural complexities also generated uncertainty in well correlations. Past experience was a series of downhole tool failures, resulting in multiple BHA runs to drill the reservoir section. Drilling caprock too deep could also accidentally expose the reservoir which would have catastrophic consequences such as total losses, well control situation, and sometimes missing the sweat zone completely.
The initiative comprised the introduction of a multi-layer detection resistivity mapping tool to detect bed boundaries with resistivity contrasts in the 8-3/8" hole section. The objective was to set the 7" liner as deep as possible to minimize the footage in the caprock in the next 5-7/8" section. Combined with in-depth well placement study to determine best trajectory for landing strategy, it enabled to push liner point closer to top of reservoir.
In subsequent implementations of this novel approach, the 8-3/8" section was deepened in average by 20 ft TVD into the caprock against the default 5 ft TVD previously followed. The drilling performance in the subsequent 5-7/8" section was significantly enhanced. Minimum shocks and vibrations were observed, and maximum drilling parameters could be applied at section start resulting in much higher penetration rates. The reservoir section was successfully drilled in two runs, doubling the average footage drilled as compared to previous similar runs. From a reservoir management viewpoint, the initiative contributed to increase the net-to-gross ratio across the pay-zone which improved the efficiency of the frac stages and eventually expanded the overall gas production.
This accomplishment was only made possible by the collaborative approach between the integrated services provider and the other stakeholders and was first deployed in a deep gas integrated drilling project. The client gave very positive feedback and the gas drilling unit is now considering implementing similar strategy in other rigs. From these promising results, it is believed that this initiative can also be implemented elsewhere in the Middle East where accurate well placement across thin carbonate layers is critical for successfully drilling the reservoir section.
Harnessing Benefits of Integrated Asset Modelling for Bottleneck Management of Large Offshore Facilities in the Matured Giant Oil Field
Authors: Nomura Yukito , Sai Shanker Ramadoss 
Published: November 2020

Abstract
An offshore giant oil field in Abu Dhabi is producing from multiple developed reservoirs with large offshore facilities including complex subsea pipeline network. However, due to increasing associated gas and water production trend, facility capacity can be insufficient in the future. Therefore, it is challenging to achieve planned oil production target. This paper demonstrates how to achieve it with cost effective mitigation method and IAM (Integrated Asset Modelling).
To achieve the objective, following organized methodology was applied. 1. Production network system modelling through history matching with the actual field observed data. 2. Integrating standalone reservoir models, production network and existing facility capacity constraint. 3. Simulating the model with specific field control method. 4. Analyzing the profile to identify the bottleneck for each period. 5. Preparing several debottlenecking options. 6. Assessment of the cost and impact on profile by debottlenecking options. 7. Proposing the most cost effective debottlenecking solution to achieve planned oil production target.
Several bottleneck issues of the existing facilities were identified through the modelling work; capacities of offshore complex separation, flaring, gas export, water processing, and gas dehydration. IAM shows those capacity constraints may cause oil production short-fall without proper management. In addition to that, friction in the subsea flowlines are also concerned because it increases back-pressure for production wells. Therefore, several mitigation options were evaluated and optimum solutions were prepared for each issue such as additional gas export line installation, converting existing subsea line to flowline, unhealthy well shut-in and additional well potential requirement, change of subsea network configuration. The study with IAM concludes all of those bottleneck issues can be mitigated by those debottlenecking options.
One of the IAM benefits is to enable us to evaluate production potential by bringing together existing information and models from all parts of the production system. It revealed various bottleneck issues within the existing giant offshore complex facilities. And it also showed how those issues can be managed by proper mitigation measures.
Diagnose of Corrosion Acceleration in Water Injection System Due to Influence of Dissolved Oxygen and Sulphate Reducing Bactria: A Case Study
Authors: Alwan Kareem A. , Al-Rubaye Wisam I. 
Published: November 2020

Abstract
Corrosion acts a major risk to water injection systems in oilfields. Dissolved Oxygen (DO) is one of the most significant causes of internal corrosion problems of carbon steel pipes worldwide. Consequently, the existing of both DO and Sulphate Reducing Bacteria (SRB) in injection water with reasonably high concentrations are greatly influencing on accelerating corrosion process in water injection system, that can severely impact costs of operations, and their control can introduce a vital challenge for the system operator.
An Iraq oilfield (Z), in which water injection for pressure support started in 2012 by five wells, then the wells number and the total injection rate are gradually increased in the following years by using both fresh rivers water and produced water. After 30 months, corrosion indications in water injection system are progressively increased. Many costly solutions are used to ensure continues water injection in this field.
In this paper, corrosion acceleration signs are observed during 5 years, to identify the corrosion status in different locations of water injection system. Corrosion indications are the leakage accidents in surface flow lines, workover operations to replace damaged tubing inside injectors, and increasing stimulation jobs as a result of the corrosion scaling accumulation inside injection wells and sand face. Many lab tests result of DO and SRB contents in water injected are collected, analyzed and in-depth studied to correlate the impact of different DO and SRB concentrations on the acceleration of corrosion problems in the water injection system.
The work results presented that the increasing of DO in water, leads to hugely acceleration of corrosion in all parts of injection system in the field under study. SRB as an anaerobic bacterium is playing a very complicated role in the corrosion of water injection system. SRB accelerates corrosion process by many ways, some of them are enhancing by DO concentration. The worst influence of SRB is expected to be grown with time when SRB go to the reservoir with injected water. SRB activity in reservoirs is reflecting by continuous upward of H2S concentration in reservoir fluids. This work introduced a reputable field experiences of diagnose corrosion process acceleration in a good case study in an Iraq oilfield, and how can reducing this corrosion speeding up by proper control of DO and SRB contents in water injected.
Introduction Of 66kV Infrastructure in UAE Offshore Oil & Gas Industry
Authors: Bin Ruken S.A.. A. , Kuwair M.B.. B. , Takieddine Oussama , R. Kamal Faris , Paul Raju , Mazumdar Sumit Kumar 
Published: November 2020

Abstract
This paper presents a case study by NPCC for the selection of offshore power distribution voltage in Al Yasat's, Belbazem Feed Project. The project involves large offshore power delivery to three ESP based WHT platform through subsea umbilical. This necessitates detailed study for the right selection of distribution voltage with an objective to minimize offshore cost.
The study involved survey of existing medium voltage transmission practice in most of the ADNOC offshore facilities and took into consideration of new technologies and development in offshore renewable energy sector with regard to 66kV infrastructure. The study considers 33kV and 66kV as the preferred candidates for comparison in offshore distribution voltage. Comparison is done based on subsea cable design, subsea power cable cross section, voltage drop, power loss, cable charging breaking current, GIS technology, CAPEX and OPEX.
For the delivery of large offshore power over long distance, the study resulted in the selection of 66kV distribution voltage. 66kV design reduces subsea cable cross section to significant extent while maintaining lower voltage drop and power loss as compared to 33kV design. Lower cable cross section results in reduction in cable weight, lower packing and transportation cost, less cable joints for long cables and increase in offshore installation efficiency. High voltage power transmission through long distance subsea cable involves substantial handling of cable charging current by breakers. The breaker tested as per IEC favors 66kV design since the breakers are tested at higher cable charging breaking limit (2.5 times) as compared to 33kV. This eliminates the requirement of shunt reactor in 66kV. New development in 66kV offshore renewable energy market such as introduction of wet type design in subsea cable, introduction of euromold cable connectors and compact GIS solutions makes 66kV design very cost competitive. The benefits which 66kV design offers lowers offshore CAPEX and OPEX.
The introduction of 66kV is novel to ADNOC and a major shift from existing practice in UAE oil & gas industry.
Successful Gas-Lift Start-Up Offshore Abu Dhabi, A Game Changer to Unlock Fields Potential and Increase Reservoir Recovery
Authors: Jaffres Benoit , Soomro Moazim , Zidan Maher , Mel Raphaele , Alblooshi Jamal 
Published: November 2020

Abstract
ADNOC Offshore started-up full field gas-lift activation for the first time in 2020. This major step will unlock field's potential by increasing reservoir withdrawal and increasing wells life by mitigating water production / breakthrough. This paper details the successful application of gas-lift from design during appraisal phase and early production stage to full field implementation. Fit for purpose design was implemented through multi-disciplinary studies and work. A strong change management in operating philosophy was requested to take onboard all stakeholders: Field development, Field Operation, Wells operation, Drilling and completion. Following appraisal and early production phases on a green field, wells design was optimized to ensure proper activation in most of the producers (two over three reservoirs developed). Due to full field development phasing, the first 30% of the wells completion were designed based on early production phase data. Before full field commissioning started, in well gas-lift valves were designed and installed, integrating all the dynamic information gathered during natural flow production. Valves change out was performed with the highest HSE standards, and taking into account full field development timing in order to reduce downtime and therefor maximize production. As gas-lift is new in the operating company, a strong change management was required: operating with gas-lift by field operation team, Completion design, Drilling and Gas-lift Production with SIMOPS. Gas Lift implementation will ensure the future oil production of the field as water injection and production will increase. Gas-lift practice implementation led to modifying the operating company's rules in multiple and deep aspects:
– Improve field team competencies in handling high pressure gas-lift system, – Increase completion and wells operation complexity, – Implement new SIMOPS rules.
As a first achievement, one well under reservoir integrity issue (low productivity due to reservoir collapse) was re-activated and production of existing wells was increased of several thousands baril. Further increase in production is expected in the following months as implementation is deployed to all required wells.
Downsized Multiskilling Program for Geoscience Students to Petro-Technical Professionals: How a Novel Integration-Based Cross Disciplinary Training for Interns Allows Reinforcing the Technical Competencies for Future Geoscience Workforce
Authors: Kelkouli Mohammed , Elghanduri Khaled 
Published: November 2020

Abstract
This paper describes a tailored multiskilling training program, newly designed for a group of students interns from different disciplines, that is based on the integration of different geoscience domains, leading to reinforce the technical competencies for future Petro-Technical workforce.
The program was inspired by an initiative launched for experienced geoscientists from different disciplines (Geophysics, Geology, Petrophysics, Petroleum ...), planning to move or recently joined a consultancy team, to help understand the full picture of consulting projects. This program was downsized and re-tailored for MSc geoscience students. While traditionally each intern works on a specific project or thematic of his domain with a mentor from his discipline (i.e. Geology student with a Geologist ...), the cross disciplinary program assumes a group of students from different domain working together as one team, for 3-6 months internship, on a single integration-based project (Field Development Plan "FDP" in our case), during that period they will be supervised by mentors for each domain.
Unlike conventional training program for students, as described in the previous section, the cross disciplinary approach allows each student to benefit from a theoretical courses-based learning in the form of class or web-based training for his domain, of course, as well as for other geoscience sub-disciplines, this is coupled with practical workshops and software learning/manipulation sessions. Hence, the intern will enrich his knowledge on other domains that were not necessarily covered during university courses. Looking outside of this mono-domain circle will help understanding what others are doing, how are they doing it, why are they doing it ... simply understand the way of thinking of each other across a consulting project team. The real benefit goes beyond that, in fact students from this program, when hired as Petro-Technical geoscientists, will easily integrate consultancy team of any size, know exactly what they have to do and why. The experience has demonstrated its effectiveness in preparing the future technical workforce.
The cross-disciplinary training program for a group of students from different domains working on a unique project, is a new concept that has never existed before. In addition, for the first time ever, university has granted these students (although from different departments) to present their MSc graduation projects together as a single project in front of a larger technical committee to cover all the disciplines.