bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Organisation-Wide Investigation Into The Human Factors-Related Causes Of Hydrocarbon Releases On Offshore Platforms
Authors: Gilroy Jenny , Dumolo Derek 
Published: September 2013

Abstract
An offshore Operator contracted Lloyds Register Consulting to conduct an independent HF-focussed organisational assessment into the underlying contributory factors to HCRs on their platforms, in order to support their own internal initiatives to reduce HCRs. The aim of Lloyds Register Consulting’s assessment was to help the organisation confirm and identify the key areas of focus in order to combat HCRs and prioritise further actions going forward.
Lloyds Register Consulting adopted a systematic approach to investigate the HF contributions to HCRs on the organisation’s platforms, including a Thematic Analysis of past incident data, offshore interviews and onshore interviews with staff and detailed analysis of findings to identify common emergent themes issues. Eight key areas were identified as priorities for further action, and Lloyds Register Consulting provided the operator with recommendations for improvements and/or remedial actions to deal with identified contributory factors
This presentation will explain the approach followed by Lloyds Register Consulting and the findings from the study, including the key Human Factors causal factors that were identified. It will also highlight the key lessons learned that are considered to be potentially relevant to the wider offshore sector.
NUGGETS Gas Field - Pushing the Operational Barriers
Authors: Saha P. , Parsa A. , Abolarin J. 
Published: September 2013

Abstract
NUGGETS subsea development in the Northern North Sea consists of 5 gas wells with 40 – 70 km tie-back to the Alwyn platform with 1st gas in 2001 and a peak production of 6 MMSCM/D of gas in 2004. Project life was expected to be 10 years with main constraints being methanol requirements for hydrate management and sealine minimum turndown.
Due to increasing water production, the wells were shut-in one after the other and the field was due to be decommissioned in 2010. At that time, minimum recommended MeOH concentration was ≈ 28% (wt/wt) which allowed a maximum water production of 40 Sm3/d. Thanks to a concerted effort to keep gas rates at targets which respected all constraints and reduce methanol use to zero, an additional 2.8 MBOE has been produced from NUGGETS. This represents an incremental recovery of about 2.0%. In addition, the field life has been extended with the possibility of further prospects being tied-in to the existing facilities.
With methanol constraints removed, new issues are subsea system life longevity and reservoir management. Current field operations philosophy is optimised to respect minimum turndown of the subsea line and the minimum gas rate per well with/without water production. It is also aimed to manage water coning in the reservoir. The reservoir has very high permeability with Kv/Kh ≈ 1 and strong aquifer influx. Moreover, numerical as well as analytical methods were used to investigate the coning.
This paper provides a critical assessment of the methods employed from a flow assurance, a well performance and a reservoir management point of view. It concludes with a set of observations and recommendations for operators of dry gas fields with strong aquifers and long subsea tie-backs.
Barrel Chasing Through Well Interventions - Can We Get Better At This?
Authors: Kitsios S. , Shields C. A. , Vroemen S. 
Published: September 2013

Abstract
This paper presents a recent initiative by European operators for improving production enhancement via well interventions. It is based on the output of a benchmarking exercise into the performance of the various intervention activities. Data is historic and the aggregated and anonymised results of the benchmarking exercise are shared only amongst participating operators. Operators meet annually to discuss technical successes and failures and to identify potential areas for technical collaboration. Collaboration projects are only kicked off once win-win situations can be defined. Results to date indicate a broad range of performance impying ample opportunities for raising both operator and industry performance. The aim of this paper is to attract more participation in this European initiative and to raise interest for replicating it in other regions.
Role of Artificial Lift in Wells With a Downhole, Flow Control Completion
Authors: Gasbarri Sandro , Muradov Khafiz , Davies David 
Published: September 2013

Abstract
Several hundred of Intelligent wells well that combine downhole flow control and monitoring have been installed over the last decade in a wide range of reservoir production scenarios. Numerous publications have reported the successful use of the technology to reduce the number of well interventions, improve sweep efficiency, reduce risk, mitigate production problems, etc. A number of zonal inflow and outflow control methodologies have been proposed to meet a wide range of different well objectives as well as different production or injection conditions. Research still continues in the areas of simple reactive or predefined passive control methods employed by Intelligent wells. This is even more true if it is planned to use proactive control which requires optimisation of a complex multivariable problem.
Efficient downhole flow control comes at the cost of adding an additional pressure loss. Such losses can be significant, jeopardizing the well productivity and sometimes carrying the risk of a reduced well performance of the intelligent well when compared to the corresponding conventional well. Installing artificial lift can compensate for this reduced well performance; not only extending the well life, but also adding additional well control flexibility. However, it also poses two extra problems: how to (a) optimally design the artificial lift equipment and (b) avoid interference between the I-well’s control of the zonal inflow and control of the artificial lift.
This paper sets out how to(1) Add control flexibility to downhole flow control by artificial lift and (2) Design an electric submersible pump that operates flexibly with down hole, multi-zone inflow control actions.
Improved active and passive downhole flow control will be discussed in a rigorous, mathematical manner that allows the conclusion that the combination of artificial lift and downhole flow control provides greater zonal flow control flexibility and reduces the inflow imbalance. Also, two conceptual, electric submersible pump design options, employing (1) a variable wellhead choke and (2) a variable pump operating frequency, are proposed and illustrated. Both of these proposed pump design options could cope with the changing well inflow performance created by downhole flow control devices in situations where the standard pump design workflow was ineffective.
Seismic Full Waveform Inversion improves Valhall Reservoir Management
Authors: Andorsen Kent , Barkved Olav , Idsøe Christian , Wrobel Lukasz , Kristiansen Tron G , Tjetland Gunnar 
Published: September 2013

Abstract
The Valhall field has been on production since 1982 and produced in excess of 800 mmboe. The primary reservoir is the over-pressured, high porosity and fractured Upper Cretaceous Tor formation. The field compacts during depletion, resulting in subsidence in the overburden.
In 2003 a permanent seismic array, LoFS, was installed across the field. The main objective of the system was to support the water flood program. To date15 seismic surveys have been acquired and the LoFS program has proved to deliver valuable information.
In monitoring of the Valhall water-flood program we were facing two fundamental technical challenges; poor p-wave seismic quality in part of the field and the presence of very thin dense, zones with pervasive fault induced fracturing. These fractures act as conduits and distribute the water away from the well.
Fortunately, the type of seismic recordings achieved using the permanent system are favorable for the use of full waveform inversion, and we have been able to produce velocity models containing much higher resolution than conventional ray-method based tomography. This model supported focusing of primary seismic reflection such that the presence of the reservoir could be interpreted from 4D seismic images, as the noise that still dominated the conventional 3D images appears to be highly repeatable and was reduced in the inherent differencing process.
Estimated Fluid Contact Using Material Balance Technique and Volumetric Calculation Improves Reservoir Management Plan
Authors: Ghahri P. , Berthereau G. , Milner S. , Orta M. , Sikandar A. S. 
Published: September 2013

Abstract
The Gryphon Field located in block 9/18b of North Sea was discovered in 1987 and originally comprised of a ~200ft thick oil rim under a gas cap with a strong aquifer. It is connected to another nearby field via the gas cap and has been producing since October 1993. One of the biggest challenges in placing future wells is that production has significantly thinned the original thickness of oil column above the oil-water contact (OWC) and the gas-oil contact (GOC) has moved up due to gas movement and production.
A methodology has been developed to estimate current water (OWC) and gas (GOC) oil contacts in the field from initial fluid in place, production and rock and fluid properties. The methodology is based on the volume of remaining fluid in the reservoir using material balance techniques and calculation of the fluid contacts assuming the whole reservoir as a single tank, and with best estimates of initial contacts and residual saturations.
Here, the contact movements have been calculated versus time. The calculated fluid contacts show a good agreement for two direct measurements of GOCs from two pilot holes. There is a 50 ft difference between OWCs from these two pilot-holes measurements; the calculated OWC is almost the average of these two values - providing confidence in the approach.
The calculated fluid contacts were also compared with recently obtained 4D seismic and up to date reservoir simulation model for different producing wells that show a good match.
The completion interval of all wells has been mapped versus the contact movements. The results show that in order to increase oil production from the current the wells, gas injection could be increased in a way that takes into account the effects of fluid movement. The wells need to be operated as much as possible at low gas oil ratio that is possible due to strong water drive. It is also shown that the datum of the new infill wells should be at a shallower depth compared to previous wells.
Ninian Southern Platform Jacket Repair Readiness Strategy: Development of a Modular Hyperbaric Habitat System
Authors: Mann Gavin , Wilson Mark , Martin Robert , Branch Ian 
Published: September 2013

Abstract
Hyperbaric welding habitats provide a dry environment where divers can perform subsea welded repairs to structures or pipelines. The Ninian Southern Platform jacket structure in the northern North Sea has suffered a history of weld defects and fatigue-induced brace failures since it was installed, a number of which have required extensive hyperbaric weld repair work.
Previous repair projects have typically been long and expensive as they have relied on a purpose built welding habitat which requires a long lead time and significant up front cost for each repair. The need to have in place a repair readiness strategy for the Ninian Southern Platform jacket, to minimise the time and cost involved in carrying out repairs to critical welds led to the development of a modular system which can allow access to a large number of different weld locations.
This paper describes the concept, design, building and testing of a unique Modular Habitat system to fit 80% of the brace welds on the Ninian Southern Platform. The design has kept diver safety as the over-arching driver, but with flexibility, speed and quality of repair as key objectives of the project.
Evolution of the design to suit the maximum number of weld configurations is explained, through detailed design to the importance of sealing onto the different brace configurations. Key to this achievement was a collaborative approach that involved CNRI, Subsea 7 and Atkins; input from diver experience of working in bespoke jacket repair habitats was invaluable. As well as developing an optimised enclosure small enough to be located in confined areas but large enough for practical working, the opportunity was taken to include state-of-the-art features in the Habitat’s integral diving system, making it as far as possible a safe and comfortable place in which to work. The design was refined by the use of full scale mock-ups, and proven by wet-testing of the completed Habitat Modules.
The Modular Habitat system plays a key role in the overall life extension strategy for the Ninian Southern Platform, ensuring that the costs, risks and production downtime associated with future subsea repairs are minimised.
New Real-Time Casing Running Advisory System Reduces NPT
Authors: Mason Colin J. , Igland Jan Kåre , Streeter Edward J. , Andresen Per-Arild 
Published: September 2013

Abstract
Casing, liner and completion running operations are key activities during the well construction process. Failure to reach the required setting depth may have a significant impact on well economics due to additional construction costs, deferred production and lost reserves. A substantial proportion of NPT (Non-Productive Time) associated with these operations is due to stuck pipe, and over many years the industry has made a concerted effort to reduce this.
A new advanced advisory system has been developed to enhance the monitoring of running tubulars into a wellbore. This web based system integrates real-time data, analytical capability and informative displays to identify early warning indicators associated with stuck pipe, mud losses and other anomalies.
The system has been used to actively monitor more than seventy casing, liner and completion running operations in offshore wells located in the Caspian Sea, offshore Trinidad, the North Sea and the Gulf of Mexico. Early benefits that have been realised include improved responses to stuck pipe early warning indicators, closer control of trip schedules, greater collaboration between offshore and onshore communities, and better informed and more impactful decision making. The system is currently being deployed at scale to offshore drilling rigs and is expected to bring additional benefits of standardisation, embedment of good practice and know how, and enhanced organisational capability.
As the industry drills longer, deeper, and more complex wells, the installation of longer and heavier tubulars into close tolerance wellbores will be required. This means that a deeper knowledge of the underlying physics and a better understanding of the limitations of tubular running equipment are required. It is envisioned that this advisory system will prove to be a mechanism to gain deeper insights into the casing running process, generate ideas for better designs and drive enhanced operational decision making.
This paper describes the concept, system design and infrastructure requirements. Case studies from various field deployments are illustrated and conclusions from experience to date summarised.
Improving the Economics of Marginal Fields through Technology Transfer from the Defence and Renewables Industries
Authors: Watson Paul , Stiven Tim , Mekhiche Mike , Edwards Kate , Sebire Tamara , Rixon James , Morris Chris 
Published: September 2013

Abstract
This paper describes how Ocean Power Technologies (OPT) successfully transferred technology developed in the Renewables sector to Defence and is currently repeating this process for the Oil & Gas (O&G) market, providing solutions that could drive down project OPEX & CAPEX to help make current fields that offer low commercial returns more attractive for development.
OPT describes the core enabling technology viz a moored, floating buoy which harvests wave energy and uses a proprietary energy management system to deliver persistent power and communications over long period multi-year deployments. It will describe a versatile marine platform which enables a wide variety of new application solutions. The system is known as an APB-350.
The results of the latest deployment of the APB-350 are described, illustrating the ability to deploy remote, in-ocean sensors and communications for subsea applications, and demonstrating the rugged survivability of the device.
It will be shown that the technology can deliver to operators a cost effective, safe, reliable, persistent power and communication platform that has the potential to reduce operational costs and improve overall production performance. Specifically, where development would traditionally require high cost power delivery systems, the technology can provide an economic solution where previously the cost was prohibitive. Potential applications are discussed in collaboration with Premier Oil such as: UUV garages for in permanent infield monitoring/inspection of assetsThe control of electric trees for CO2/water field injectionEnvironmental monitoring for pre-post deploymentReal-time on site field monitoring/sensing systems for 4D reservoir analysis and pre/post deployment surveysSecurity Cordons for offshore developmentsTemporary navigational markers for surface & submerged structures
Conclusions will be drawn regarding how the transfer approach used will benefit the oil and gas industry, to improve current operations and deliver alternative, more cost effective solutions. The ability to power alternate sensor packages and high power delivery functions, will enable operators to obtain, real-time data for remote field operations; thus allowing remote real-time asset management and enabling better monitoring and control of overall performance and safety.
Real Time 24/7 Integrity Monitoring of Mooring Lines, Risers and Umbilicals on an FPSO using 360 degree Multibeam Sonar Technology
Authors: Lugsdin Angus 
Published: September 2013

Abstract
For new build FPSOs or to safely extend the life of ageing assets, operators require technologies that enable them to safely monitor the subsea infrastructure in real-time, to identify problems before they occur. Annual inspections by Remotely Operated Vehicle (ROV), although useful to provide close up inspection, do not provide real-time information in the event of a mooring line failure or problem with the risers.
Through the application of multibeam sonar technology, operators can now have real-time 24/7 information on the presence and position of mooring chains, risers and umbilicals. Unlike other acoustic techniques, multibeam sonar does not require additional sensors mounted to each mooring chain or riser, therefore removing the need for regular maintenance, servicing and power source replacement by ROVs.
The multibeam sonar system provides autonomous alarms in the event of mooring line or bend stiffener failure and the accurate sonar data can be used for further fatigue analysis, assisting in the planned maintenance schedule.
This unique technology was developed for BP and has been successfully deployed on an FPSO in the North Sea, where it has provided round-the-clock integrity monitoring capability. This technology was selected in 2013 for permanent deployment on a new build FPSO entering service in the North Sea with production planned for 2015.
Providing Additional Offshore Resources Using "Walk to Work" at the Captain Field
Authors: Pena Gerald , McKeown Stephen 
Published: September 2013

Abstract
Across many offshore assets in the North Sea and around the world, a common challenge that Operators are continually encountering is the ability to complete desired work scopes in a bed-constrained environment.
In the summer of 2012, in order to facilitate the execution of key fabric maintenance and subsea/marine integrity scopes, the Operator utilised a relatively new solution called "Walk to Work" (W2W) at the Captain Field as a means to increase the number of available man-hours offshore to complete the work.
W2W is a term used to describe the use of a gangway installed on a vessel to transfer personnel to/from the installation at the beginning and end of their shifts. Day and night shift personnel transfers from the vessel facilitates 24-hour working on the installation, thus increasing the number of available man-hours.
The key enabling elements that the Operator addressed were the selection of the W2W system & W2W vessel and the installation of the W2W landing platforms. In addition, other key activities such as regulatory approval, Independent Verification Body approval, safety reviews, and campaign maintenance planning were imperative to the success of the project.
The W2W project at Captain delivered key business results for the Operator. A new solution to the common problem of lack of beds offshore was utilised effectively. Although it may not be the solution to every project, W2W operations should be considered as a viable alternative to conventional means of adding extra resources offshore.
Cement Sheath Integrity in Fast Creeping Salts: Effect of Well Operations
Authors: Jandhyala S. , Barhate Y. R. , Anjos J. , Fonseca C. E. , Ravi K. 
Published: September 2013

Abstract
A number of reservoirs around the globe are in deep environments, and often it is necessary to drill and cement through salt sections to reach them, such as in offshore Brazil. These reservoirs are mainly in deep water and are commonly referred to as pre-salt zones. It can be very challenging to drill and cement the salt section. The salt zones could be a few hundred meters thick, creep at high rates, and when in contact with drilling fluid and cement slurry, their chemical properties can change. The effect of salt movement or creep is addressed in this work.
Salt formations pose a unique challenge to the structural integrity of the wellbore by applying a time varying load on the cement sheath and casing. This load is caused by the existence of deviatoric stress and temperature variations. Deviatoric stress is the difference between formation in-situ stress and the wellbore fluid’s hydrostatic stress. When a salt formation creeps during a well operation, it does so to achieve a hydrostatic state such that the deviatoric stress is zero.
The present work is a study of cement sheath integrity under downhole thermo-mechanical loading conditions using finite element analysis (FEA). The effect of salt creep on the stresses experienced by the cement sheath at various stages in the life of the well, including drilling, cementing, shut-in, completion, and production, are simulated. A material model for salt creep is validated against experimental data reported in the literature. Multiple cement systems are compared for their effectiveness in providing zonal isolation for the life of the well. The effect of structural and thermal loads due to salt creep on cement are quantified through stresses in cement.
The method discussed in this paper should help the industry select cement formulations that can withstand stresses caused by salt movement during the life of the well. Method and case studies pertaining to offshore Brazil are presented and discussed in this paper.