bluuebunny/crossref_metadata_2025_split huggingface dataset:
Re-Floatable Towed Production Systems for Small Pool Development
Authors: Goodlad M. , Hopkins D. , Hendawy M. 
Published: April 2018

Abstract
The Re-floatable Towed Production System Program was instigated to develop a methodology for re-floating, re-positioning and re-installation of a subsea system for marginal fields/small pool developments.
The Towed Production System incorporates either small or large subsea processing manifolds/towheads at the ends, connected together with a Pipeline Bundle. This provides a complete subsea system installed in a single offshore operation.
When installed, a towed production system is ballasted for added on-bottom weight to withstand operational, environmental, and trawling impact loads. To achieve this weight the annulus of the bundle is filled with treated seawater while the main structural members of the towheads are filled with a combination of barite slurry and seawater. This paper will examine the methodology to remove this added ballast in order to re-float the entire system.
The ability to re-float a towed production system unlocks the notion of re-using subsea infrastructure. While historically Pipeline Bundles have shown to be configurable for specific field applications, a standardization of the Pipeline Bundle and integration of subsea processing, as used within this study, can enable the asset to be used over multiple field locations. This includes, but is not limiting to, the use as a development tool for small field exploitation. This will add value to the system as a cost-effective solution for subsea field developments.
A key to the re-use of subsea infrastructure is integrity monitoring, including the demonstration that after re-positioning the product it is fit for purpose with sufficient remaining design life. The paper will also detail the related development work conducted on fibre optic monitoring within the Pipeline Bundle section.
I3P HPHT Checklist for Design Minimum Acceptance Criteria
Authors: Andampour Jay , Hoefler John 
Published: April 2018

Abstract
For decades the design methodology for the development of conventional (surface) and unconventional (subsea) drilling and completion equipment has been utilizing very conservative (non-optimized) and inconsistent approaches.
As oil and gas technology advances into deepwater and high-pressure high-temperature (HPHT) environments, the demands on the equipment's design integrity, efficiency, optimization, and safety have significantly increased, since failures and the associated recovery processes could be very expensive. It is the original equipment manufacturer's (OEM) responsibility to establish high confidence that the operator's assets and businesses are safe, sustainable, and dependable.
The oil and gas industry uses applicable American Society of Mechanical Engineering (ASME) standards, American Petroleum Institute (API) standards, operator's functional specification, and Bureau of Safety and Environmental Enforcement (BSEE) regulation as guidance for product design and development, and their acceptance criteria define the limits placed on characteristics of material, products, and services. Material selection/testing, design verification analysis, and design validation testing establish what standards are used to evaluate every aspect of the equipment design, testing, and manufacturing.
The purpose of the BSEE guidance document is to present conditions under which approval may be granted for the use of well completion and well control equipment that is capable of performing in a deepwater and/or HPHT environment.
The API 17TR8 serves as a nonmandatory technical report guideline for HPHT equipment, specifically for subsea applications.
API standards were intended to adopt the design methodology from the ASME Boiler and Pressure Vessel Code (BPVC), Section VIII, Divisions 2 and 3, which has been used in the oil and gas industry since the 15th edition of API Specification 6A published in 1986.
For example, the original API 6A adopted a design stress intensity of two-thirds of the minimum specified yield strength and a membrane stress intensity of 83% of the minimum specified yield strength. API 6X/17D and 16A adopted their own acceptance design criteria independent of each other and ASME VIII, Division 2. The independent third party (I3P) consequently decided to develop an I3P HPHT Checklist for the Design Minimum Acceptance Criteria to clarify those issues by identifying any deficiencies existing among API standards and to provide a methodology consistent with ASME VIII, Divisions 2 and 3, 2013.
Hebron Offshore Development Project Overview
Authors: Wolfe K. J. , Parker G. J. , Sellars S. L. 
Published: April 2018

The Hebron Offshore Development Project, offshore Eastern Canada, is one of the world's most ambitious oil projects. In November 2017 ExxonMobil Canada Properties (EMCP) commenced oil production from this world scale engineering marvel located in 93m of water approximately 350 kilometers southeast of St. John's NL in an area known as the Grand Banks.The Hebron platform consists of a Gravity Based Structure (GBS) with a storage capacity of 1.2 million barrels of oil and an integrated steel topsides structure. The integrated topsides design with total operating weight capacity of ~65,000 t contains drilling and production facilities with a peak production capacity of 150,000 barrels per day (bpd) and a living quarters for 220 people. The field infrastructure also includes a subsea Offshore Loading System (OLS) providing crude offloading capability to tankers and a fiber optic cable loop linking the offshore platform to an onshore network enabling enhanced digital technology implementation. The project was sanctioned on 31 December 2012 and first oil occurred on 27 November 2017, ahead of schedule.This paper discusses the Project from design through execution and highlights several of the unique design features, execution sequence and specific challenges which were faced. Special technologies were employed and project management initiatives implemented which enabled the success of the project.
Automated Remote Monitoring of Offshore Assets Using Satellite Imagery and Machine Learning
Authors: Araujo Maria S. , Davila Daniel S. , Blaisdell Samantha G. , Van Horn Adam 
Published: April 2018

Abstract
Satellite imaging technology continues to progress toward providing reliable, real-time remote monitoring of offshore asset health and safety. The fast growth of satellite constellations which offer high-resolution observation data over all weather conditions generates opportunities to monitor, predict, and report on a variety of incidents. This paper discusses a new satellite imaging monitoring technology with a case study focus on marine oil slick detection.
Currently, typical applications of this technology face several limitations common to many remote sensors, such as reliance on a human-in-the-loop and the limitations imposed by individual sensors onboard a weight- and downlink-limited spacecraft. This paper discusses recent work in which deep learning was applied to multiple satellite imagery streams operating in different spectral bands to automatically detect oil slicks on the ocean surface. Different imagery streams were registered in space and time to create multidimensional composite images. These images were then used to train a deep neural network classifier to detect if oil is present or not present.
The results of this work demonstrate that it is now possible to overcome several key limitations of satellite sensing technology. First, by leveraging multiple satellite sensors in parallel, both primary sensing modalities can be used to overcome the shortcomings of either. Second, initial results from the output of the machine learning classifier will be presented, showing that it is both feasible and advantageous to trust an algorithm for automatically monitoring offshore assets for leak events. When the human is removed from the loop, the time and cost it would have taken to manually review satellite imagery are significantly reduced, in turn increasing efficiency and operability. Lastly, additional potential applications that this work enables will be discussed.
Multispectral imagery fusion overcomes the individual limitations of the sensors for oil slick detection and asset monitoring. Machine learning overcomes the human-in-the-loop limitations, allowing for reliable, automated, and large-scale monitoring necessary for offshore applications.
DeepStar Technology Advancement Related to Floating Systems and Operations Impact
Authors: Gomes Joseph , Shamshy Shakir 
Published: April 2018

Abstract
DeepStar® is an operator funded offshore Technology Development consortium which provides an open collaboration environment between oil & gas (O&G) companies, vendors, regulators and academic/research institutes which started in 1991. This program has been on the forefront offshore knowledge and technology development within the oil and gas industry, with a focus on issues related to continuous operations, flow assurance and industry standards. The program has progressed in the industry, the understanding and mitigation techniques pertaining to hydrate blockage and with the advancement of modeling software, preventative measurements, and chemical treatment has allowed the industry to move from hydrate avoidance to a hydrate management strategy. The program continues to advance the hydrate blockage remediation tools available to the industry by providing an update to modeling software related to multi salt reservoir hydrate modeling or proposing deployable hydrate blockage remediation tools in case of a prolonged shutdown.
Under the lower for longer oil price environment, a quest for a step change cost reduction solution is an active discussion amongst the industry, highlighted above being able to reduce downtime due to flow assurance issues is one important topic, although as asset age another topic of continued service become an ever-evolving topic. DeepStar has worked extensively on this topic for many years advancing the industry dialogue and assisting with updated industry standard related to integrity management related to floating systems, mooring lines, and risers. Highlighted within this discussion is the industry project on Riser Integrity Management reviewing the industry program framework and future riser database that is being developed. For most facilities the riser component is the most expensive portion of floating production systems and once the riser is retired the facility is decommissioned.
Re-Shaping LNG Transfer
Authors: Lagarrigue Vincent , Hermary James 
Published: April 2018

Abstract
The LNG market remains in relative infancy in terms of the development of infrastructure to meet increasing supply and demand. Given its unique make-up compared to traditional oil and gas transposition, new and innovative means of transferring LNG have had to emerge; factoring the unique composition of LNG (i.e. chemical and physical properties) and the critical importance of safety while loading and unloading.
Moreover, LNG Infrastructure is moving into new frontiers for a variety of reasons. LNG exporters are seeking new markets and evolution of small and medium scale LNG demand will necessitate splitting of LNG into smaller load parcels. Power generation, and LNG terminals, are being constructed in locations that have traditionally been ‘off-grid’ – disconnected from pipelines. More flexible options are required to fit a broader range of vessel sizes, locations, weather conditions and infrastructure conditions.
One key element in unlocking new transfer options is fresh thinking around ship-to-shore transfer and the development of game-changing floating composite cryogenic hose technology.
Composite LNG hoses typically consist of multiple, unbonded, polymeric film and woven fabric layers encapsulated between two stainless steel wire helices – one internal and one external. Essentially, the film layers provide a fluid-tight barrier to the conveyed product, with the mechanical strength of the hose coming from woven fabric layers. The number and arrangement of multiple polymeric film and woven fabric layers is specific to the hose size and application. The polymeric film and fabric materials are selected to be compatible with the conveyed product and the operating temperatures likely to be encountered.
This technology cost-effective technology has enabled a recalibration of traditional thinking around ship-to-shore LNG transfer. Designed for fatigue resistance in even the most hazardous conditions, cryogenic floating hose technology typically provides a viable alternative to traditional jetty-based transference in circumstances that would make such infrastructure unfeasible – for example, harsh environments, areas where water is too deep to accommodate jetty construction, or too shallow to allow large vessels to moor alongside.
These cryogenic hoses also expand options for offshore ship-to-ship transfers in a broader range of locations; for example, in tandem configuration, vessels can be moored as much as 300 to 500 meters away from a storage unit. This enables ship-to-ship transfer in deeper waters in even the most challenging conditions - with the increased separation distance mitigating the risk of collision and ensuring the safety of the vessels and crew.
In this paper, we will discuss the multiple applications of cryogenic floating hose technology and how it is re-shaping ship-to-shore and ship-to-ship transfer.
Temporary Coating for Dissolving Frac-Balls Used in Multi-Stage Fracturing Systems
Authors: Kumar Deepak , Hernaez Erwin D. , Sanchez James S. , Xu Zhiyue 
Published: April 2018

Abstract
One challenge with dissolving frac-balls used in remote multi-stage fracturing systems is their premature disintegration in the ball-launcher used for the deployment of balls downhole. As a solution, a "temporary" coating was developed which prevents disintegration of frac-balls until they land on the desired ball-seat downhole. The current paper discusses laboratory tests conducted to qualify the coating.
Two types of corrosion resistant coatings were studied: phenolic based and aliphatic based epoxy. Laboratory tests were conducted to verify that the coatings satisfied service requirements: coating remained intact in the ball launcher filled with frac-fluid for a few days, ball maintained its pressure rating even after extended exposure in the frac-fluid, and the ball disintegrated to the outer diameter, which enabled the ball to fall through its associated seat within a week. In-situ tests comparing disintegration rates of coated and uncoated balls were conducted to determine if coating interferes with the eventual disintegration of the frac-balls downhole.
Results showed that the phenolic coating provided better protection to the frac-balls than the aliphatic coating. Further, a thick coating must be applied to prevent any disintegration of the frac-balls in the launcher, because thin coating failed locally along the microscopic defects. Pressure test results demonstrated that the coated balls formed a tight seal with the seat up to its pressure rating. After landing on the ball seat the coating failed, allowing the frac-ball to disintegrate per the service requirement, and fall through the seat in a timely manner. Thus, it is concluded that phenolic based epoxy coating can be used to protect the dissolving frack-balls in hydraulic fracturing tools.
FLNG - Pushing the Boundary of Existing Practices
Authors: Abe Shigeru , Ishizaki Hiroyuki , Uchida Hirokatsu , Nitta Kotaro 
Published: April 2018

Abstract
In the history of FLNG development there were significant achievements recently, with symbolic events, namely the Petronas FLNG Satu started her LNG production in December 2016 in Malaysia and the Prelude FLNG having been sailed away to her destination in Australia in mid-2017. Since the concept of floating LNG was discussed by the industry in the 1990's, it has taken nearly three decades for the dream to come true through the resolution of technical and commercial challenges. The Petronas FLNG2 and the Eni Coral South FLNG will follow, to be delivered together with LNG carrier conversion solutions. The authors together with their colleagues have been deeply involved in all phases of the development programme, from concept selection, definition and execution in delivery of the majority of these projects. This paper captures our actual experience, challenges and lessons learned, and address our observations to facilitate further improvements and enhancements in project delivery, competitiveness, quality and safety.
Qualification of the HighBoost Multiphase Pump for Heavy Oil Applications
Authors: Knudsen Halfdan Rognes , Bibet Pierre-Jean , Ekeberg Ina , Marthinussen Svein Arne , Kjellnes Hans Fredrik , Torbergsen Erik Andre 
Published: April 2018

Abstract
Some of the world's largest reserves are heavy oil reservoirs, defined as liquid petroleum of less than 20°API gravity or more than 0.2 Pa.s (200 cP) at reservoir conditions, [4]. Production of heavy oil in combination with increasing water cut (WC) brings a potential for very high emulsion viscosities. In combination with gas, the high viscosity provides operating conditions highly challenging to multiphase subsea pumps.
In 2013, OneSubsea was awarded the Engineering, Procurement, and Construction (EPC) contract for Total's Moho 1bis development in the Republic of the Congo in West Africa. The contract included a subsea pump station with two 3.5 MW HighBoost pumps (helico-axial multiphase pump with balance piston) capable of handling high viscosities and gas volume fractions (GVFs).
As part of the Moho project, and to qualify the HighBoost technology for high viscosities, a full-scale test loop was built to verify pump performance at liquid viscosities up to 0.8 Pa.s (800cP). To cover the complete Moho operating range 0.001-0.8 Pa.s (1-800cP) and 0-75% GVF, the first article pump was tested on nitrogen and three different liquids: water, hydraulic oil, and gear oil. An extended analysis on the performance of helico-axial pumps in this unexplored domain of laminar and transition flow regimes was carried out.
Extensive amounts of test data were gathered during the 2-year qualification period. After testing and design optimization, the pump performance was significantly higher than predicted. The knowledge gained also served as valuable input to the pump protection logics customized for high-viscosity pumping. During the program the pump has proven its ability to perform startups on viscosities up to 30 Pa.s (30,000cP).
Qualification of this technology for high viscosity has widely extended the domain of high power, high flow and high differential pressure (dP) helico-axial multiphase pumps. Along with their proven track record in deep water and long step-out distances, the ability to pump high-viscosity fluid will enable future development of other heavy oil reserves going forward. The pump system described in this paper was successfully installed, commissioned, and started during the spring of 2017 to boost the viscous production. As of January 2018, it has been running with 100% availability following the startup.
How to Improve Sweep Efficiency of Horizontal Wells for Offshore Fluvial Oil Reservoir by ICD Inflow Control Device
Authors: He Yifan , Shi Hongfu , Luo Xianbo 
Published: April 2018

Abstract
This paper discusses the development challenges of an offshore fluvial oil reservoir with horizontal well. In highly productive sandstone reservoirs, horizontal wells suffer from uneven flow profile and subsequent premature coning effects because of sand heterogeneity and heel to toe effect. Moreover, excessively increasing the rate or horizontal well length can increase the risk of limiting sweep efficiency, resulting in bypassed remaining oil in the toe or poor sand with low permeability. Firstly, we anlayse the characters of fluvial oil reservoir focusing on architecture and heterogeneity. Secondly, the sweep efficiency was calculated by the production data of existing horizontal wells. Lastly, we optimize ICD (inflow control device) for several wells and compare the response of ICD wells with standalone wells.
Modular Integration Platform – Submerged Production Unit for Large Subsea Plants
Authors: Daasvatn Sigbjørn , Juhlin Rasmus , Sæterdal Morten 
Published: April 2018

Abstract
Installation of large subsea processing systems requires expensive specialist offshore construction and heavy-lift vessels. An alternative to larger lifted structures is towed structures.
A cost-effective, versatile and open technology platform alternative has been developed, starting from the experience based on the design and installation of towed pipeline bundles for more than 35-years /1, 2/. Together with experiences from design, installation and operation of subsea plants and with the application of new materials, this has led to the new Submerged Production Unit (SPU) concept.
This paper describes how the SPU, in combination with a modularised integration principle for payloads, can be applied for extensive industry collaboration on integration of existing and new subsea technologies to form large subsea production solutions replacing surface based production solutions.
Model-Centric Digital Subsea Pipeline Design Process and Framework
Authors: Laye A. , Victoire K. , Cocault-Duverger V. 
Published: April 2018

This paper describes a development initiative intended to reduce significantly design cost and duration using digitalization. Subsea pipeline design, and in-place studies in particular, is a complex process that is broken down into a systematic sequence of calculations, all connected to a normalized and serialized meta model. The pipeline digital data model is interpreted by a framework that distributes and collects design data to various algorithms and software, thus automating the entire pipeline design workflow down to production of standardized design reports.
The implementation of such an objective requires:
Developing a systematic design methodology, covering industry standards as well as the client's special requirements, under a "one-size-fits-most" process; Standardizing a data model serving as a meta-model to necessary models and solvers; Standardizing data format and exchange protocol so that all models are served with required inputs and instructions; Coding design procedures as unitary applications collecting inputs from and relaying relevant results to the data model; Integrating applications into a framework that serves inputs and collects outputs from models and calculations to produce final standardized reports.

Design reports with input data, results and methodology are automatically created or updated under various file formats or templates. Engineering productivity is improved drastically and the impact of rework is minimized. The productivity gain is multiplied when the design is still in the early stage and when multiple multi-disciplinary design cycles, including the stakeholder's review, are necessary.