bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technical Challenges of the CLOV Oil Loading Terminal
Authors: Brinkhuis H. , Dormans K. , Jones A. , Ming M.T. 
Published: April 2015

Abstract
This paper considers the key technical challenges experienced by Bluewater Energy Services BV during the design, fabrication and load-out of a deep water buoy, also referred to as the Oil Loading Terminal (OLT) for Total E&P Angola, acting as Operator for and on behalf of a Consortium.
The OLT buoy was contracted for the Cravo, Lirio, Orquidea, Violeta (CLOV) Field Development Project, located offshore Block 17 in Angola, about one nautical mile from the Floating Production Storage & Offloading (FPSO) unit. The preferred way for offloading will be through the Oil Loading System (OLS), comprising of two Oil Offloading Lines (OOLs), two Fibre Optic Cables (FOCs) and one OLT.
Bluewater Energy Services BV entered into an Engineering, Procurement and Construction (EPC) contract for the OLT buoy including mooring lines, mooring hawser system, floating hose system and suction piles. During the execution of the work, the key technical challenges may be summarized as follows:
The impact of the deep water environment (ranging from 1,100 to 1,400 meters) on specific mechanical equipment. The design of the double pivoting chain stoppers, extensively tested at full scale. The interface with the Oil Offloading Lines (OOL) resulting in two large steel structures (the OOL receptacles) underneath the bottom plate of the buoy body. This in combination with the available lifting capacity at the fabrication yard in Angola, imposed limitations on the way the OLT buoy could be placed into the water.
ACG Field Geohazards Management: Unwinding the Past, Securing the Future
Authors: Hill Andrew W. , Hampson Kevin M. , Hill Andrew J , Golightly Chris , Wood Gareth A. , Sweeney Michael , Smith Martyn M. 
Published: April 2015

Abstract
The super-giant ACG field lies in the Azerbaijani sector of the south Caspian Sea. The significant complexity of the geohazards setting over the field was realized in 1993 when negotiations for the PSA to develop the field were still ongoing.
This resulted in the need to understand geohazard risks being recognized in the Minimum Obligatory Work Program terms set out in the "Contract of the Century" in September 1994.
Over the last twenty years work to define and refine understanding of the multiple geohazard issues has been ongoing. Work started in early 1995 with the completion of two deep geotechnical boreholes and a PSA contract area wide geophysical and geological geohazards campaign that delivered an early, first pass geohazards stop-light map and supported delivery of the Early Oil Project (1997).
The results of these two initial pieces of work formed the basis of the first PSA contract area wide integrated geohazard study that addressed the threats of individual sources of geohazard to Full-Field Development planning. These included, amongst other issues: slope instability, mud volcano stand-offs and fault risks, all being included in the first integrated geohazards risk map of the PSA's contract area in 1999.
Since this time, direct experience, in drilling and facilities installation, has driven the need for an ongoing update of data and improvement in geohazard understanding. New sources of hazard, such as the implications to riser-less drilling from super-saline soils, have had to be assessed and new data acquired to assist in mitigation of the risks identified.
Most recently HR3D data has been acquired across the entire PSA which, tandemed with AUV seabed and shallow profiler imagery has been used to guide a further series of geotechnical campaigns. These results have been used to drive an update to the geohazards zonation addressing, in particular, slope instability in field areas previously considered too sensitive for development.
This paper provides a timeline of geohazards activity on the ACG PSA over the past twenty years as a background to other papers being offered in the technical session that discuss how specific geohazard data acquisition and analysis issues have been addressed.
GIS-Based Probabilistic Slope Stability Assessment Using Shear Band Propagation
Authors: Rushton David , Gray Thomas , Puzrin Alexander , Hill Andy 
Published: April 2015

Abstract
This paper describes a GIS-based application of shear band propagation to model slope instability that combines rapid analysis over large areas using pixel-based analysis with an approach capable of modelling the observed slope failures.
Slope instability modelling can be performed over large study areas through application within a GIS. This approach typically involves calculating the limit equilibrium factor of safety using an infinite slope geomechanical model for a dense grid of pixels covering the study area. The result is a quantitative and spatially resolute estimate of susceptibility to slope failure representative of the seabed gradient, sediment strength and density, and other conditioning or triggering factors. For input to a spatial risk assessment, factor of safety can be converted into annual probability of failure using a Monte Carlo assessment to capture the uncertainties in the inputs and the modelling approach.
Shear band propagation offers an alternative to limit equilibrium and provides a simple approach to modelling to the long and relatively thin slope failures typically observed in the offshore environment. This method is applied probabilistically, resulting in a numerical map of annual probability of slope failure through shear band propagation. The complexities of applying a two-dimensional model within a three-dimensional spatial framework are explored in this paper.
This GIS-based probabilistic slope stability assessment using shear band propagation has been successfully employed as part of a landslide risk assessment of the Azeri-Chirag-Gunashli (ACG) development, Caspian Sea, where pixel-based annual probability of failure estimates contribute to a landslide risk score for each geohazard province within the area.
Managing Obsolescence Risk for Subsea Production Control Systems Through the Implementation of a Proactive Obsolescence Management System
Authors: Akbar Iqbal , Bertmand Trond , Broadbent Paul , Cotton Mark , MacKenzie Rory , Smith Harvey 
Published: April 2015

Obsolescence can be a significant cost driver and impacts equipment at all stages of the whole life of field. The life cycle of parts within major long life products can be significantly shorter than the life of the products they are within.
Obsolescence risk when installing and maintaining existing and future Subsea Production Control Systems (SPSs) is therefore of significant concern to the industry as there is an ever increasing demand to extend the operating life of equipment. Whilst the largest risk is with electronics and electro/mechanical items, the requirement is to manage all types of parts used in the design, manufacture and support of SPSs and associated topside equipment.
A Subsea Obsolescence Management Joint Industry Project (JIP) was established to address the significant obsolescence issues being experienced by Oil & Gas operators as they attempt to upgrade ageing infrastructure or repair failures.
The objective of the JIP is to make available a recommended practice that could be freely used by any/all operators in the industry, as required. The intention is that a common practice used by all would minimise the different types of methods employed within the major suppliers to manage obsolescence. To help in this respect the JIP has produced a Recommended Practice (RP) for Subsea Obsolescence Management. This recommended practice relates directly to the requirements of a Joint Operator Specification (JOS) that was collaboratively developed by a group of operators and released in 2012.
This paper will present the key activities undertaken by the JIP and show how they have implemented, and are continuing to improve, a proactive obsolescence management capability into the Subsea Systems supply base.
Creating Sustainable Offshore Developments in the Ultra-Deep Water
Authors: Rijtema Saskia , de Haas Ramon 
Published: April 2015

Abstract
The continuous drive to increase oil and gas production requires fields to be developed under challenging circumstances such as deeper water, harsh operating & environmental conditions and remote areas all while adhering to strict HSE requirements. At the same time, investment decisions for an increasing number of projects have been postponed because the increasing costs have resulted in reduced shareholders return.
In order to overcome the technical challenges within the changing environment, funding needs to be created by improving the cost effectiveness of the adopted solutions. This can be achieved by optimizing and standardizing the current concepts and by using the research in and outside our industry, to benefit from innovations, which can reduce risks and save costs. At the same time, lessons captured in the past decade need to be imbedded within the organizations which requires retaining, training and guidance of the engineers and building on the technical relations within the supply chain.
The other side of the deep-water challenge is the current technical limitations, which need to be overcome. Equipment that is currently available and their applications need to be revised to deliver the step change to the ultra-deep water.
This paper will focus on the areas, which combine our extensive installation experience with our more recently gained SURF EPCI insights and the ongoing technology developments with the intent to create practical solutions for the industry. It will describe how we intend to use real time simulators to identify and manage risks during the offshore construction. Also, topics such as lowering capabilities for the ultra-deep water, flexibility in field developments, smart design which incorporates vessel capabilities, coating & welding developments for the high pressure, high temperature fields and the implications of remote areas will be addressed.
Process Safety KPI's - Wells and Drilling Activities
Authors: Carvalho F. A. F. , Lopes M. T. 
Published: April 2015

Abstract
An essential element of any improvement program is the measure of existing performance needs, as well as identification of new and future needs. This paper presents Process Safety KPI's (Key Performance Indicators) for Wells and Drilling activities, created by a committee in a Brazilian Energy Company comprised by experienced professionals with expertise in those activities. The continuous improvement of Process Safety Management in this company leaned on four steps: accidents (definition of process safety anomalies), competence, diagnostics and implementation of effective leading and lagging process safety metrics. The company understands that said continuous improvement can be achieved through the definition of accidents, incidents and Process Safety deviations, awareness promotion, process safety training (developed in cooperation with the Corporate University), definition of Process Safety Management elements at corporate level and development and implementation of effective leading and lagging process safety metrics with periodic critical analysis.
Monitoring and analysis of results derived from Process Safety Indicators provide inputs to the continuous improvement process in Safety Management. In fact, these results make it possible to focus efforts on the weaknesses identified and to determine potential opportunities for improvement. Furthermore, throughout the maturation time of these indicators, it is possible to verify those that are most representative for the process under analysis and the need for reformulation or exclusion of some metrics during the trial period.
Overview of BC10 Deepwater Development - An Effective and Efficient Phased Approach
Authors: LeBlanc Jeanne-Marie , Soares Andre , Boyd-Gorst John , Stingl Kent 
Published: April 2015

The Parque das Conchas BC-10 deepwater development is a combination of several distinct small to mid-size fields that allow for phasing. The fields are off the coast of Brazil in 1800+/- meter water depth. This series of successfully phased projects started with the deployment of the Espirito Santo FPSO, 11 wells and subsea boosting equipment in Phase 1 which came on-stream in July 2009. Phase 2 followed on-stream in October 2013 with an additional 11 wells (including water injection), subsea boosting equipment, and brownfield topsides upgrades on the FPSO. The Phase 3 investment has already added 7 wells and will come on-stream in early 2016 after the subsea and topsides scopes are completed. The success of this phased development is attributed to rigorous standardization, rapidly applied learnings, and strategic deployment of new technologies.
Maintaining the cost competitiveness and economic value of each new investment phase was more difficult, given the decreasing size of the fields developed. Leveraging contractual partnerships and using standardization of well design and subsea hardware led to improved quality, competitiveness and delivery schedule (corrected for market factors).
Technologies deployed during the project included mudline boosting through Electrical Submersible Pumps (ESPs) (and later, in Phase 2, multi-vane pump inserts to increase gas handling capacity), transmission of high voltage electrical power through subsea umbilicals, real-time geosteering and permanent reservoir monitoring technology. A 6th generation Bully Class rig was successfully used in Phase 2, and after replication efficiencies, coupled with focused improvements to the drilling scheme, the rig and crew performed flawlessly for the Phase 3 wells, delivering the scope several months ahead of schedule.
Another challenge was committing to pre-investment for the later phases. For example, water injection facilities were pre-installed with the Phase 1 project, for use on Phases 2 and 3. Taking this investment decision early had risk attached, but this has paid off. This paper highlights the advantages of a phased approach, as well as how the learnings can be used in successive phases to improve overall project value.
The strategy of a phased approach to the development of BC10 enabled quality business decisions, and optimized the ullage utilization of the FPSO. Continuity of resources to continuously learn and rapidly apply learnings proved highly successful.
An Application of Computed Tomography Inspection on Butt Weld of Super Duplex Umbilical Tube
Authors: An Xiaoxue , Brambilla Marco , Dobson Alan , Francois Olivier 
Published: April 2015

Abstract
Super duplex stainless steel (SDSS) tube is a main component in steel tube umbilicals to convey hydraulic fluids, chemicals or to control the flow of gas into subsea wells. Butt welds are used in the umbilical tube manufacturing for all tube joints and their quality directly impacts the in service performance of the steel tube umbilical.
The butt welds are 100% inspected by X-Ray radiography. The obtained images are 2D shadowgraphs of a 3D object and, as such, they are limited in providing the exact depth of the defects inside the weld and part of geometry information of the weld is easily lost. To address this radiography limitation, the acceptance criteria of NDT are therefore very strict, and generally no porosity is allowed within the butt welds. As result, high rejection rate can be observed for thick wall tube (WT &gt; 2.5mm). This limitation can be overcome by replacing X-ray radiography with X-ray Computed Tomography (CT). This technique provides a full 3D picture of the butt weld and allows enhancing the weld quality and improves productivity by reducing rejection rate caused by lack of information on the flaw depth through the wall. The technology can constitute a step change in the Non Destructive Testing (NDT) technology for the production of umbilical tubes.
This paper presents the results of the X-ray CT inspection of umbilical tube butt weld and the concept design of a computed tomography machine for on line butt weld inspection. The machine is based on a computer controlled rotating gantry on which an X-ray source and a digital detector are installed. This gantry can perform a 190° rotation, during which several hundred radiographic projections of the inspected weld can be acquired under different view angles. A purpose developed image reconstruction software processes the acquired data to provide the full 3D representation of the weld.
The article describes the selected X-ray chain, the reconstruction algorithm and the effect of the reduction of the number of acquired projections on the resolution of the 3D image of the weld. The study demonstrates that CT is a very pertinent technique for the inspection of butt welds in an industrial production environment, with superior accuracy compared to film or digital radiography. The combination of a dedicated CT machine and state of the art reconstruction algorithm can provide volume information of the weld flaw, for example gas pores, as small as 5 % of the tube's nominal wall thickness (150 ^m for a 2.7 mm WT tube), showing the ease of interpretation of CT images with respect to classical radiographies.
Oil Offloading Lines and Fiber Optic Cable Package
Authors: Nehme R. , Dethoor X. 
Published: April 2015

Abstract
As part of the CLOV project located offshore in Angola (Block 17) developed by TOTAL E&P ANGOLA, SBM OFFSHORE has been awarded a contract to provide the Oil Offloading Lines (OOL) and Fiber Optic Cables (FOC) sub-package.
The scope comprises the Engineering, Procurement, Supply, Construction and lnstallation (EPSCI) of OOL, FOC and associated sub-packages onboard the Oil Loading Terminal (OLT) and FPSO such as receptacles and winches as well as the transportation and installation of the OLT.
The OOL and FOC packages have been through an extensive design phase followed by detailed qualification testing program of each of their components. A number of improvements and lessons learnt from previous projects have been accounted for.
The two 600mm (24") lD OOLs have a length of 2058 m and transfer crude oil from the FPSO to the export tanker moored to the OLT, making these OOL the largest diameter oil export system ever made. The OOLs are made by the assembly of Trelline™ flexible bonded hoses with some sections of buoyancy modules in order to have a so-called 2 arches configuration. The OOL is hung off at each end (FPSO and OLT) by means of Gimbal Tables. The Gimbal Table is an articulated mechanical connection with a low friction double articulation designed to transfer the tension from the OOLs to the structural components of the FPSO and OLT.
The two FOC consists of 12 pairs of fibers housed in a gel filled steel carrier tube surrounded by a polyethylene sheath and layer of steel wires that form a protective vault against pressure and water ingress. The FOC are secured at each end (FPSO and OLT) to the l-Tubes using Bending Stiffeners laid in a lazy-wave configuration using buoyancy modules near the seabed.
Developing Mega Projects Simultaneously: The Brazilian Pre-Salt Case
Authors: Filho Flavio Gonçalves Reis Vianna , Naveiro Jaime Turazzi , de Oliveira Andrea Pontual 
Published: April 2015

AbstractThis article discusses the development of several mega projects for the development of the Pre-Salt fields, in the Santos Basin, deepwater, offshore Brazil. Special focus is given to the Lula Field, a super giant field, operated by Petrobras, having BG Brasil and Petrogal Brasil as partners.Discovered in 2006 and with an estimated potential recoverable volume up to 8.3 billion barrels of oil equivalent (boe), Lula field placed pre-salt fields in the spotlight as it opened a new prospective frontier in Brazilian deep waters. To develop Lula field, a multi-module development project, it was adopted a fast track strategy to achieve material production levels in a very short time frame.In such a massive capital expenditure program, in an area with no infrastructure, and in an environment of heterogeneous carbonate reservoir, risk mitigation actions are a must. The first step taken was to acquire static and dynamic reservoir data, through data acquisition wells, extended well tests and implementation of two pilot FPSOs. Also, flexibility in the projects was carefully evaluated aiming to comply with possible bad, and good, reservoir surprises.This information was used to optimize the development plan of Lula field, which comprises 10 FPSOs with processing capacity ranging from 100k bpd to 150k bpd of oil, and 175 million cubic feet/day to 280 million cubic feet/day of gas. The two pilot production units started operation in 2010 and 2013, respectively, and the first module of Iracema area in Lula Field started production in October 2014. The following FPSOs are expected to be installed in the upcoming years.In a scenario of simultaneous projects under implementation, a clear long lead items strategy is critical to ensure the planned fast-track pace. Also, standardization of subsea equipment and production platforms, in an increasing local content requirement, mitigates supply chain risks and allows resources allocation flexibility.This paper details the key success factors of Lula field development strategy, and show why it is nowadays a reference for the following mega developments that will take place in the Brazilian pre-salt, by combining a risk mitigation strategy with a fast pace production ramp-up, anticipating cash flow funds and maximizing returns.
Subsea Factory–Standardization of the Brownfield Factory
Authors: Økland Ole , Ramberg Rune Mode 
Published: April 2015

AbstractAs part of the corporate technology strategy Statoil has launched a technology plan for the Subsea Factory concept. The plan describes how to combine subsea production and processing technology elements with key business cases and define enabling and cost-efficient field development concepts.With the advent of moving processing facilities from topside to subsea, Statoil has made major technological advances in placing conventional processing equipment on the seabed. As of today, Statoil has successfully deployed subsea pumps and subsea separators (Troll Pilot and Tordis). Statoil is also in the process of deploying the world's first subsea compressors in 2015 (at both the Åsgard- and Gullfaks field).While there has been a gradual increase in the complexity of the subsea processing systems we have also advanced our analytical and modelling approach to subsea processing concept evaluation and selection. In our recent concept evaluation we have used an integrated modelling approach, in which subsea processing options are directly linked to reservoir models, flow lines and surface facilities. This enables us to see value added in terms of increased reservoir productivity, but also overview of entire system behavior from reservoir to the topside, throughout the expected field life.The cost level within subsea has increased by a factor 2.5 over the last 10-12 years. Statoil aims at establishing a Business Agreed Standardization on subsea processing interfaces and modules.This standardization strategy will allow suppliers to compete within modules/technology elements, but standardize on module size and open interfaces to achieve plug-and-play functionalityThe goal is to reduce costs and improve competitiveness of subsea solutions:More profitable subsea developments Increased subsea processing volumeStatoil believes that alignment with the other operators is vital to succeed in establishing a global, open standard.Standardization enabling cost reduction through simplification More profitable subsea developments Increased subsea processing volume (? win-win-solution for the O&G industry)The paper describes the ongoing work to achieve standardization of the Brownfield Subsea Factory with focus on near infrastructure solutions of existing fields. Subsea boosting and compression are important technologies enabling extended lifetime and increased recovery of mature subsea fields. In the paper several business cases will be described.