bluuebunny/crossref_metadata_2025_split huggingface dataset:
Dropped Object Incident Reduction Utilizing a Robust Verification Program
Authors: Marsden Arnold Riley 
Published: April 2020

Abstract
Dropped objects are commonly one of the largest contributors to high-potential near misses and injuries in projects and other aspects of the Oil and Gas business. The objective of this paper is to describe an innovative and powerful technique used on the Appomattox Project at multiple work sites to greatly reduce the number of high-potential dropped object incidents.
Despite extensive preparations to manage the risk of dropped objects, the Appomattox Project experienced a flurry of such dropped object incidents at one of its fabrication sites in 2017. The Project responded by launching a robust verification program leading to a six-fold reduction in the frequency of such events. Subsequently, the Appomattox Project applied the program to all its other significant work scopes with an ambitious goal of reducing high-potential dropped objects by 75% or more. The two critical aspects of the program were the collection of quality leading indicator information at the front line and timely and relevant action by site leaders based on that information.
Through unwavering leadership support, partnership with its contractors, and attention to detail at the front line, the Appomattox Project beat their goal and completed the final 15 months of the Project with zero high-potential dropped object incidents outside of controlled, exclusion zones. The Project team actively shared its learnings with other projects in the company, contributing to a 22% reduction of such incidents in its global portfolio from 2017 to 2018.
While many types of assurance and verification programs exist, this rigorous application to dropped object incident reduction was a novel and valuable addition to an already strong Project HSSE management system and yielded exceptional and immediate benefits.
Development and Implementation of Heavy Wall High Strength Sour Service Accessory and Risers for HPHT Application in the Gulf of Mexico
Authors: Landier Carine , Oliveira Jonathas , Gomes Christelle , Parezanovic Ivana , Tricarico Mike , Cole Stuart 
Published: April 2020

Oil and gas development needs in the Gulf of Mexico have continued to push into High Temperature and High Pressure (HPHT) applications. Along with the HPHT requirements, the need for sour service resistance has also grown. To meet these needs, large OD and heavy wall pipe with sour service capability have been specified. To answer this need Vallourec has pushed limits of wall thickness with sour service properties far beyond the standard. This was done for both heavy wall accessories as well as for riser application. Outer diameters ranged from 13 inches to over 23 inches, with wall thicknesses of 2.5 inches.
These sizes are common in lower strength material, but to meet the high-pressure requirements, Vallourec was able to provide up to 125ksi specified minimum yield strength grade material. Higher grade material allowed supported cost savings and select elimination of some Corrosion Resistant Alloys (CRA) components. It also allowed much lighter weight pipe as compared to 80ksi specified minimum yield strength material that is standard for sour service applications in oversize OD and heavy wall.
To develop such heavy wall pipes with sour service resistance, the heat treatment process has been the most critical step. Quenching the material to reach this level of performance requires the heat-treatment lines to be designed with state-of-the-art and robust heat-treatment equipment.
This paper will discuss the material properties achieved on several of the large diameter, heavy wall, sour service pipes.
Prelude’s Remarkable Turbomachinery - The Story From Selection To First Drop Of LNG
Authors: Mossolly Mounir , Bustos Emmanuel , Messineo David 
Published: April 2020

Abstract
This is the story of the remarkable turbomachinery of the Prelude floating liquefied natural gas (FLNG) facility that was selected, designed, manufactured and extensively tested to achieve the highest levels of technical assurance, to serve what was the FLNG facility ever sanctioned in the world, a pioneering project destined to be an exemplary success.
The Prelude FLNG project is unique for its size and numerous innovations. Its large onboard turbomachinery is usually applied at this size only to onshore liquefied natural gas (LNG) plants. The technical requirements of the Prelude FLNG facility went far beyond the limits of offshore experience, with consequences on the selection and design of the onboard turbomachinery. The management of this new technical solution was successfully achieved using detailed modelling and engineering analysis, an extensive test campaign using purpose-built test beds, and the development of dedicated start-up and operating procedures.
This paper focuses on the pumping heart of this largest offshore facility ever constructed: the main refrigerant compressors and steam turbine generators, in addition to the seawater lift pumps that are used to extract seawater from a water depth of 150 meters, sustaining the main cooling capacity for the FLNG facility. The paper also mentions other sophisticated machines such as the combined boil-off gas (BOG)/end-flash gas (EFG) compressor, amongst others.
Extraordinary work has been performed to ensure that each step in the realization of the turbomachinery for Prelude FLNG was an incremental success. Proper preservations, precise and careful installations of turbomachinery in steel modules, as well as preparations for start-up during the pre-commissioning and commissioning phases are explained.
Common Gas Detector Guidelines that Result in Poor Designs
Authors: Marszal Edward M , Oulton Andrew Thomas 
Published: April 2020

Abstract
Fire and gas detection equipment placement has shown to be increasing in complexity over time. Over the years rules of thumb or heuristics have been developed to assist in the proper placement and optimization of the fire and gas system. Due to the judgement involved in these heuristics, the same set of "rules" can result in radically different designs depending on an individual's experience and expertise. Additionally, these heuristics can cause overall poor placement due to the fallacy that the underlying assumption is always valid.
Production Reinstatement and Facilities Enhancement Justification for a Hydrate Prone Deep Water Oil Field
Authors: Daramola Babalola , Alinnor Chidubem Martins , Orti Ngutor 
Published: April 2020

Abstract
This paper presents the lessons learnt during an intervention to remove a gas hydrate blockage and reinstate oil production from an oil well in Field D. It also uses economics to justify facilities projects for hydrate prevention and flow assurance. Field D is a deep water oil field with 10 subsea production and water injection wells tied back to a floating, production, storage, and offloading (FPSO) vessel.
Field D was shut down for turnaround maintenance work during the summer of 2016. After the field was brought back online, one of the production wells (D2) failed to flow. An evaluation of the pressure and temperature data suggested that the well had a tubing restriction. This was attributed to hydrate formation and blockage caused by limited methanol injection capacity.
A number of attempts were made to induce the well with no success. A subsea intervention vessel was then hired to execute a clean out intervention operation, and this restored oil production from the D2 well. To minimise hydrate blockage and oil production losses, the asset team completed a feasibility study to evaluate the viability of installing a second methanol umbilical and a test separator.
The hydrate clean-out intervention reinstated oil production from the D2 well, and the feasibility study suggested that installing a second methanol umbilical and a test separator are economically attractive as standalone or joint projects. It is recommended that flow assurance strategies are regularly updated as production fluids change over the lives of petroleum fields, from dry oil production to high water cut production.
This paper presents hydrate remediation steps in a producing oil field, and outlines practical methods to justify methanol umbilical capacity enhancement projects.
Prelude Turret Mooring System: A 10,000-Ton Mooring Force Challenge
Authors: Betthaeuser Francois , Mazarguil Vincent , Naciri Mamoun , Lefebvre Timothee , Masterton Stephen , Van Haaften Ewoud 
Published: April 2020

Abstract
The Turret Mooring System (TMS) for the Shell Prelude FLNG (Floating Liquefied Natural Gas) facility consists of a Top Mounted Internal Turret (TMIT) integrated at the bow of the FLNG hull. Permanently connected to the seabed through a dedicated mooring system, this Turret allows the FLNG facility to passively weathervane in response to prevailing weather conditions and enables transfer of fluids and utilities (in both directions) between the subsea wells and FLNG topsides. This paper describes the challenges faced during the engineering and construction of the most challenging TMS ever executed to date.
Prior to Prelude, SBM Offshore (SBM) had designed for Shell a TMS suitable for a large range of gas compositions from a portfolio of remote offshore gas fields, including North-West Australia, in water depths ranging from 165m to 1,350m, with the generic FEED vision "engineer one, build many". The Prelude TMS was finally developed with a detailed design to meet the specifics of the 250m field water depth and to remain safely on station for 25 years in cyclonic weather conditions. To achieve the robust design target, field proven solutions were revalidated for application at a greater scale, for a longer design life, harsher environment and the high reliability demands of the project. The execution strategy followed the requirements of TMS contractor direct and end Clients.
The TMS, located very close to the bow, moors the 488m long, 74m wide Prelude FLNG hull. The system will ultimately accommodate 8 production risers, although only 4 are presently installed. The mooring system design is governed by the 10,000-year storm, resulting in a weathervaning system comprising 40 bogies, 40 radial wheels and 32 lower pads transferring the load to the hull. The mooring arrangement is composed of 4 bundles of 4 lines each, with 175mm R4 chains at top and bottom, and a mid-water section of 162mm sheathed diameter steel wire rope.
Several challenges have resulted from the requirement to comply with a complex set of codes and standards, the severity of the cyclonic conditions, the record size of the FLNG hull, and from the required capacity of mooring components pushing beyond the existing industry experience base.
Lessons learned from a selection of key challenges encountered during the engineering and construction of this one of a kind TMS will be presented with a view to facilitating future developments offshore North West Australia.
Developing Environmental Performance Indicators for Early Phase Engineering of Facilities and Fields
Authors: Purse Luke 
Published: April 2020

Abstract
Environmental performance indicators are a tool for engineering service providers to enhance the visibility and understanding of environmental impacts amongst study teams when designing offshore facilities.
This paper presents the rationale for selecting certain indicators, and some of the challenges inherent to certain facility functions, and limitations set by various study types. It explores publicly available indicators which may be usable as benchmarks, and covers field, topside (both greenfield and brownfield) and subsea facilities.
Genetic Algorithms to Solve the Jonswap Spectra for Offshore Structure Designing
Authors: Rueda-Bayona Juan Gabriel , Guzmán Andrés 
Published: April 2020

AbstractThis research applied a Genetic Algorithm model to identify suitable JONSWAP spectra parameters for specific locations, solving restrictions such as the influence of bathymetry and met-ocean events that could limit the coefficient selection of the spectra. Also, this study assessed available parametrized equations of the JONSWAP spectra in order to verify their applications for easing the application of the GA model. The modeled results demonstrated the capability of the GA model to find the best alpha and gamma values of the spectra for normal and extreme sea state conditions. In addition, the assessed spectra parameterized equations evidenced limitations to represent the wave energy distribution at the study area, then, this study performed a successfully modification of one of these parameterized equations to model the proper JONSWAP spectra. According to the results was evidenced the necessity to apply numerical approaches such as Genetic Algorithms to solve wave spectra equations for offshore structure designing, and the assessing of support parameterized equations before their application because the wave loads could be wrongly estimated.
Digital Transformation through Integrated Power & Process
Authors: Lau Constantine Chuan , Mancuso Bernardo Martin , Jalal Shebin , Oguro Aislan 
Published: April 2020

Abstract
Integrated automation and electrical control systems are vital for project optimization, system simplicity and operational flexibility in electro-intensive O&G plants. Value of integrated systems through the life-cycle of the plant from design & engineering to construction and operation is widely understood as having a positive impact on CAPEX and OPEX as well as the reliability of operations. Digital twins of the plant and the process hold key information to maximize operational profitability and optimize asset performance. Next generation of digital-ready integrated process and power management system architectures enables digital performance management of plant-wide assets and processes. An evolving approach is the integration of power and process systems throughout the lifecycle of the plant, commencing at the plant design phase and progressing to the operational stage. The improved operational efficiency brought up by integrated power and process control systems through greater situational awareness, improved reliability, and faster troubleshooting extends the value of this integrated approach to operations & maintenance lifecycle. The comprehensive approach to power and process integration is achieved through seven value driven strategies that spans the lifecycle of a process plant.
Effective Boiled Off Gas/Fuel Gas Balance between Floating Liquefaction Facilities and Carrier Resulting in Zero Flaring During Offloading
Authors: Wong Kinfai , Hashim Rose Sapinah , Yamamoto Yosuke , Furubayashi Yugo 
Published: April 2020

Abstract
The interest of achieving zero flaring during Liquefied Natural Gas (LNG) offloading operation is governed by the following factors, i.e. safe operation with zero Loss of Primary Containment (LOPC), green environmental impact with lower greenhouse gas emission, maximizing the profit value of LNG, increasing the asset reliability and bringing good reputation to the company. The proper fuel gas and Boiled Off Gas (BOG) balance management between Floating LNG (FLNG) facility and LNG Carrier (LNGC) is critical during offloading operating to ensure the system reaches equilibrium and lead to zero flaring. This paper is to demonstrate the process study of identifying the potential causes of flaring during LNG offtake and the corrective measures to accomplish zero flaring without any plant capital modification. The gas flaring minimization study was based on the actual offloading operations data with multiple enhancements throughout the study. The intent is to identify the most optimum conditions that bring in the highest efficiency with the least amount of gas flaring. The outcome of the study suggests two methods which involve procedural changes during offloading operations as follows: Alteration of Boiled-of-Gas (BOG) compressor suction pressure controller set point to a higher value to accommodate additional BOG vapor accumulation in the storage tanks as temporary buffer, preventing sudden fuel gas flow surge to the fuel gas system which lead to excess flaring.Application of new offloading pattern by balancing BOG/ fuel gas flow to avoid pressure spike due to large amount of ship vapor return flow at certain LNGC tanks level.
The flaring gas minimization techniques were applied in actual LNG offloading operation in June 2019 and successfully achieved zero flaring through the collaborative effort between FLNG and LNGC. This optimization methodology is proven to provide advantages by bringing in cost recovery and maximizing the profit values of LNG production. The methodology does not involve additional capital modification and the achievement during the actual implementation can serve as benchmark study for other FLNG facilities. This paper also provides insight on the potential area of improvement opportunity to the FLNG facilities that are currently under detailed design or construction phase.
The Newly Published BSEE Guidance Documents for the Approval of HPHT Equipment, Wells, and Projects in the Gulf of Mexico
Authors: Lan Christy Michelle 
Published: April 2020

Abstract
The Bureau of Safety and Environmental Enforcement (BSEE) first published High Pressure/High Temperature (HPHT) regulations at 30 CFR 250.807 in 2010. Additional HPHT regulations were published in 2016. In 2019, BSEE published three (3) Notices to Lessees and Operators (NTLs) to provide clarification and guidance regarding BSEE's implementation of the regulations. The NTLs also provide recommendations, which if followed, facilitate BSEE's review and approval of HPHT equipment and well designs.
The following NTLs formalized the guidance BSEE has been providing operators through the Conceptual Plan approval process: NTL No. 2019-G03 "Guidance for Information Submissions Regarding Site Specific and Non-Site Specific HPHT Equipment Design Verification Analysis and Design Validation Testing" provides guidance on information that an operator should submit concerning material selection, design verification analysis, design validation and functional testing processes, and procedures. It also explains BSEE's recommendations on how an operator could prove that HPHT equipment is fit-for-service in the applicable HPHT environment. Lastly, it provides guidance on Independent Third Party (I3P) and Operator Expert Reviewer (OER) reviews and reports.NTL No. 2019-G02 "Guidance for Information Submissions Regarding Proposed High Pressure and/or High Temperature (HPHT) Well Design, Completion, and Intervention Operations" provides recommendations and clarifications regarding operator HPHT well design, completion, and intervention operations information submittals that, if followed, facilitate BSEE's review and approval. Additionally, it provides guidance on I3P and operator reviews and reports.NTL No. 2019-G04 "Requesting Approval to Consider External Hydrostatic Pressure Effects When Calculating Internal Pressure Containment Capability for Pressure Containing and Pressure Controlling Subsea Equipment" provides guidance regarding the information that BSEE needs to analyze an operator's alternate equipment request, pursuant to 30 CFR 250.141, seeking approval to consider external hydrostatic pressure in the design and calculation of internal pressure containment capability of subsea equipment.
The paper will focus on NTL No. 2019-G02 and NTL No. 2019-G03 (HPHT NTLs). The HPHT NTLs walk the reader through the required plans and reports an operator must submit and the voluntary plans and reports an operator may submit when requesting a review of HPHT equipment or a HPHT well design by BSEE. The HPHT NTLs describe the information BSEE requests in each plan and report in order to complete a review. They also outline the requirements for independent reviewers of HPHT equipment and well designs and provide guidance regarding report preparation and presentation. If any statement in this paper is inconsistent with the regulations or the NTLs, the regulations and NTLs govern.
How Technology Enables A Lower Cost for Subsea Tiebacks
Authors: Bacati Fabrice , Arcangeletti Giorgio , Breuskin Bruno , Giolo Riccardo , Muguerra Philippe , Radicioni Alessandro , Shaiek Sadia , Sibaud Elvire 
Published: April 2020

Maximizing the use of existing topside facilities is an attractive approach to reduce project CAPEX and therefore unlock new reserves. However, as the tieback length to the host increases, technical and economic challenges arise. These include flow assurance, and costs of the umbilical and flowlines which inherently increase with length. These aspects, together with others independent from the length, such as power and space availability, have a significant impact and could result in making the project unfeasible or uneconomical.
Technologies developed in recent years, or in their final stage of qualification, play a significant role, not only in solving the technical challenges, but also in finding cost-effective configurations, either by reducing and/or staggering capital and operational expenditures or by extending reserves recoverability or also by reducing significantly the risks associated with a development.
In order to appreciate these advantages, different configurations have been outlined starting from those allowed by the conventional technologies and comparing them to the ones enabled by the new technologies. Actual advantages of each technological "bricks", considered alone or in synergies, depend on the specific projects and can be identified in a timely manner thanks to early engagement of Contractor in the architecture and associated pricing of subsea tiebacks.
The paper will present a platform of technologies, their maturity status and how they can be integrated in novel architectures in an economic manner. Such technologies include:
Boosting
Distributed and local heating
Subsea water treatment and injection
Subsea separation
Subsea chemical storage and injection
All electric control system
Local power generation
Digital Representation of an Offshore Greenfield on the Sakhalin Island Using Integrated Modeling Involving Subsea Production System
Authors: Shakirov Roman , Khaliulin Ruslan , Boyarskiy Sergey 
Published: April 2020

Abstract
Development of greenfield-type fields with a gas cap and oil rims on the shelf of Sakhalin Island is always associated with a high level of geological and technological risks.
To assess the investment attractiveness of the projects, it is necessary to provide an in-depth elaboration of the concept, considering many uncertainties of both the geological structure and the development strategy and the subsea construction scenarios.
A modern approach to risk assessment involves the mathematical modelling arrangement of the entire chain of technological processes from the interpretation of seismic data to the calculation of the material balance of the installations for the preparation of produced products.
Integrated modelling at the current stage of technological development allows exploring many combinations of uncertainties in terms of the impact on the final hydrocarbon production profile and, accordingly, the economic indicators of the project.
Possibilities of integrated modeling today are not limited to conceptual field design development. The result was the creation of an effective production planning tool for one of the most promising offshore fields of Sakhalin Island.