bluuebunny/crossref_metadata_2025_split huggingface dataset:
Jubilee Project Overview
Authors: McLaughlin Dennis Carl 
Published: April 2012

Abstract
The Jubilee Project was a very ambitious challenge for the first significantdevelopment ever offshore Ghana. The Joint Venture used a split operatorship toexecute a world-class deepwater project in an area with no existinginfrastructure, in less than 3 years from the start of concept selection. Thispaper will highlight the approach used to manage the Jubilee risks and projectexecution, emphasizing the keys to success and lessons for this fast-trackedproject.
Kosmos Energy was appointed Technical Operator for the project withresponsibility to assemble and lead the Integrated Project Team (IPT) inplanning and executing the project. Tullow Oil was appointed the Unit Operator(UO) with the responsibility to drill and complete wells, build the in-countryinfrastructure and organization for production operations, and to subsequentlyoperate and manage the field in the future. Anadarko, a non-operating partner, seconded a significant number of experienced key project personnel to the IPT, enabling the IPT to fully leverage the capabilities of the majorpartners.
Jubilee first oil occurred on 28 November, 2010 and the field continued to rampup production and injection as wells were completed into 4Q 2011. Despiteseveral significant technical and commercial hurdles, the project achievedexcellent HSE, schedule, and cost performance. The IPT continued to support theUO's production operations post-first oil, and the final commissioning of gascompression/injection systems was achieved late 2Q, 2011. While there have beenthe normal challenges with shaking down a large and complex production system, overall uptime performance has been very good at &gt;95% in the first year ofproduction. Jubilee's unique circumstances justified a very aggressiveappraisal development strategy and dictated an unconventional approach toorganizing and managing the project, which ultimately was highlysuccessful.

Introduction
The Jubilee Field was discovered in June 2007 in the Gulf of Guinea, approximately 60 km offshore Western Ghana. It is a very large, light, sweetoil accumulation in 1200–1500m of water. The Jubilee Partners, along with GhanaNational Petroleum Corporation (GNPC) decided in January 2008 to develop thefield using a phased approach, after just one appraisal well. Kosmos Energy wasappointed Technical Operator to lead an Integrated Project Team (IPT) inexecuting the development project and Tullow Oil (Ghana) was appointed UnitOperator to execute in-country activities, deliver wells, and operate andmanage the field in the future. A third major partner, Anadarko, providednumerous key project personnel to the IPT. The IPT developed a plan to targetjust under 300 million barrels in Phase 1 with a 17-well subsea well system and120,000 bopd FPSO. Phase 1 was approved by Partners in August 2008, and FirstOil was achieved in November 2010, within the aggressive goal set by GNPC andthe Jubilee Partners.
Jubilee Field FPSO--A Fast Track Delivery Success
Authors: Weinbel Robert Cory , Araujo Ronaldo 
Published: April 2012

Abstract
The Jubilee Field is a deepwater development located approximately 60 kmoffshore Ghana that was executed over 3.5 years between discovery and first oilproduction. Meeting this aggressive schedule required the fast-track executionof the turret-moored FPSO, named Kwame Nkrumah, as the FPSO was consistently onthe project's critical path schedule. A key to successful delivery of the FPSOon the fast-track schedule was establishing a strategy and adhering to thestrategy even under multiple challenges. The details of the fast-trackstrategy, the challenges imposed, and the actual performance of the FPSOexecution team in delivering the FPSO safely to location will be covered inthis paper. This work also highlights the importance of building amulti-discipline team driven by clear, well-understood goals, creating astructure suited for execution, and of selecting the right Contractors for theproject and building strong relationships with them.
Although fast tracking major O&G development projects is often a statedobjective for many projects, few achieve the performance achieved on Jubilee. This work illustrates the establishment of a solid strategy and successfulexecution of that strategy to deliver an FPSO to the site in 22 months fromaward of contract. Despite the effort put in place to meet an aggressiveschedule, the project team still encountered some significant challenges duringthe execution of the FPSO design, engineering, and construction. The key tosuccessfully resolving these challenges was the team's ability to stay true tothe execution strategy as well as develop a response plan to meet thechallenges and implement it successfully and safely.

Introduction
The Jubilee Field was discovered in June 2007 in the Gulf of Guinea, approximately 60 km offshore Western Ghana. It is a very large, light, sweetoil accumulation in 1200–1500m of water. The Jubilee Partners, along with GhanaNational Petroleum Corporation (GNPC) decided in January 2008 to develop thefield using a phased approach, after just one appraisal well. Kosmos Energy wasappointed Technical Operator to lead an Integrated Project Team (IPT) inexecuting the development project and Tullow Oil (Ghana) was appointed UnitOperator to execute in-country activities, deliver wells, and operate andmanage the field in the future. A third major partner, Anadarko, providednumerous key project personnel to the IPT. The IPT developed a plan to targetjust under 300 million barrels in Phase 1 with a 17-well subsea well system and120,000 bopd FPSO. Phase 1 was approved by Partners in August 2008, and FirstOil was achieved in November 2010, within the aggressive goal set by GNPC andthe Jubilee Partners.
LNG Fueled Offshore Support Vessels in the Americas
Authors: Vollmers Tony 
Published: April 2012

Abstract
This paper details the strong incentives to use gas as a marine propulsionfuel. The gas fuel ship is a very attractive option considering theenvironmental and economic drivers even though the gas fuel support systemsinitially cost more and are a challenge to arrange within the ship. The scopeof the paper covers the pros and cons of the use of:–LNG fuel for marine applications,–Diesel scrubber technology versus utilising natural gas–Classification and regulatory hurdles–Some offshore support vessel arrangement considerations.
There has been a significant amount of interest and discussion in recent monthsin the US regarding the application and benefits of using natural gas as asource of fuel for marine vessels. There are many examples of vessels (LNGcarriers, passenger, patrol, ferries, etc.) currently in operation usingnatural gas in Europe; however, it has been slow to progress in North Americaas a fuel for operating vessels.
International class societies have been overseeing the design and operation ofnatural gas fuelled vessels for over a decade now; however, most classsocieties have only recently created or put into force gas propulsionguidelines and rules. Luckily, most of the guidelines and rules are similar innature because they have been developed from roadmap International MaritimeOrganization guidelines. Although the American Bureau of Shipping has draftrules that follow the intent of the international rules, the US Coast Guard hasadditional domestic interpretations of the international rules that areconsidered more stringent. In order to suit the particular regulations in theUS, the configuration of the vessel plays a large part in the ability to fit anLNG propulsion system without sacrificing cargo capacity, especially foroffshore supply vessels.
The capital investment for gas fuelled propulsion and the associated gasdistribution equipment is large but the return on investment is achieved in arelatively short amount of time if the costs of the gas fuel are compared withultra-low sulphur diesel and the cost of urea for the selective catalyticreactor (SCR), and the SCR itself. A conservative annual estimate for thesavings in fuel costs are 2 to 2.5 million USD when compared to conventionaldiesel fuel. Long term maintenance costs for the gas engines is also purportedto be less and still more cost effective to maintain compared to an SCRsystem.
Jubilee Development Installation, Hookup and Commissioning and Ready for Startup
Authors: Culembourg Laurent , Weinbel Robert Cory , Mutimer Keith 
Published: April 2012

Abstract
The world-class Jubilee Field Development located 60 km offshore Ghana beganPhase 1 production in November 2010, just 3.5 years from its discovery. Thispaper highlights the challenging but successful execution of the in-countryInstallation, Hookup and Commissioning (IHUC) Phase of the project inconjuction with Operations Readiness and Assurance (OR&A) activities tosafely bring the production system to an on-time Ready for Startup (RFSU)condition to meet the aggressive schedule. This paper highlights the keys tosuccess during the IHUC Phase including the use of an Integrated Project Team(IPT), close Contractor relationships, proven technologies, exceptionalcommunication, and the design-for-safety concept. Some of the executionchallenges faced by the IPT during this phase are also discussed along with thestrategies implemented such as organization structures, interface planning, tools, systems, and specific results.
Although fast-tracking major oil and gas development projects is often a statedobjective for many projects, few achieve the performance achieved on Jubilee. This work illustrates the successful integration of a multi-partner projectteam, the management of critical interfaces, and the technical and logisticschallenges with major Contractors during the IHUC Phase. Despite theengineering and planning effort put in place to meet the aggressive schedule, the project team did encounter several unexpected events during the IHUC Phasewhich required quick response to keep the project on schedule. The key tosuccessfully resolving these challenges was linked with the overall executionstrategy of empowering the team to quickly develop and implement response planswith the proper assurances that allowed the project to move ahead.

Introduction
The Jubilee Field was discovered in June 2007 in the Gulf of Guinea, approximately 60 km offshore Western Ghana. It is a very large, light, sweetoil accumulation in 1200–1500m of water. The Jubilee Partners, along with GhanaNational Petroleum Corporation (GNPC) decided in January 2008 to develop thefield using a phased approach, after just one appraisal well. Kosmos Energy wasappointed Technical Operator to lead an Integrated Project Team (IPT) inexecuting the development project and Tullow Oil (Ghana) was appointed UnitOperator to execute in-country activities, deliver wells, and operate andmanage the field in the future. A third major partner, Anadarko, providednumerous key project personnel to the IPT. The IPT developed a plan to targetjust under 300 million barrels in Phase 1 with a 17-well subsea well system and120,000 bopd FPSO as illustrated in Figure 1. Phase 1 was approved by Partnersin August 2008, and First Oil was achieved in November 2010, within theaggressive goal set by GNPC and the Jubilee Partners.
Jubilee Field Subsea Production System Design and Delivery
Authors: Cain Richard 
Published: April 2012

Introduction
The Jubilee Field was discovered in June 2007 in the Gulf of Guinea, approximately 60 km offshore Western Ghana. It is a very large, light, sweetoil accumulation in 1200-1500m of water. The Jubilee Partners, along with GhanaNational Petroleum Corporation (GNPC) decided in January 2008 to develop thefield using a phased approach, after just one appraisal well. Kosmos Energy wasappointed Technical Operator to lead an Integrated Project Team (IPT) inexecuting the development project and Tullow Oil (Ghana) was appointed UnitOperator to execute in-country activities, deliver wells, and operate andmanage the field in the future. A third major partner, Anadarko, providednumerous key project personnel to the IPT. The IPT developed a plan to targetjust under 300 million barrels in Phase 1 with a 17-well subsea well system and120,000 bopd FPSO. Phase 1 was approved by Partners in August 2008, and FirstOil was achieved in November 2010, within the aggressive goal set by GNPC andthe Jubilee Partners.
Challenged to achieve first production in less than 3 years from start ofplanning for production facilities, the IPT quickly evaluated developmentoptions and chose the predominate West Africa model of a subsea productionsystem connected to a Floating Production Storage and Offloading (FPSO) vessel. It was immediately clear that the subsea production system design, procurementand delivery in 21 months would be key to maintaining the fast trackschedule.

Subsea System Delivery Team and Philosophy
With a proven track record of deepwater project delivery, major partnerAnadarko seconded, several key IPT members to the project, including the SubseaSystem Delivery Manager. Many of the processes, relationships and executionphilosophies from their experience were combined with the Technical Operator'sphilosophy and experience to establish a " fit for purpose" strategy for projectexecution driven by the fast track delivery requirement. The success of thisstrategy relied heavily on the major vendors providing field proventechnologies and " off the shelf" solutions and the experience of the SubseaSystem Delivery Team. Within this strategy, the Team was empowered to maketimely decisions with minimal management involvement. The adoption of the " fitfor purpose" strategy for the execution of the project was also applied toprocurement processes as well. The resulting efficiencies realized in theseareas facilitated the fast, safe pace required by the project.
Another important part of the strategy was to develop the team concept. The IPTfostered a Jubilee Team philosophy with all contributors a part of " The Team" versus representatives from their respective companies resulting in adedication by all to meet the challenge imposed by the project schedule.
New Generation Control System for 20 KSI Subsea BOP
Authors: Shanks Earl F. , Reynolds Scott , Daley Harold , Williams Danny 
Published: April 2012

Abstract

Description of the Material
This paper describes the reasoning and methods used to design, develop, andtest a 7500 psi differential pressure Subsea BOP Control System. This systemintroduces the necessary upgrades and enhancements to existing control systemsfor application on the very demanding 20,000 psi Subsea Ram BOP Stacks. ManyDrilling Contractors are requiring additional features on 20 ksi BOP Systemssuch as additional Ram Cavities and larger Shear Ram Operators which requiresignificant additional control fluid at higher pressure. The 7500 psi controlfluid supply requires fewer accumulators and delivers greater usable fluid thanconventional 5000 psi systems.

Application
The BOP Control System is enhanced to supply 7500 psi differential pressurefrom the surface supply to the accumulators on the Lower BOP Stack. The surfacehydraulic power unit, HPU, and accumulators supply the diverter and othersurface requirements and supplies the subsea BOP through the riser conduit(s)and hot line. The rigid conduit manifold distributes the 7500 psi hydraulicsupply between the LMRP accumulators, redundant pods, and lower BOPaccumulators. 7500 psi to 5000 psi step down regulators supply fluid to podmanifolds and Lower BOP Stack functions.

Results, Observations and Conclusions
Development of the key components of the 7500 psi system include, surface HPU, various sizes of regulators, SPM function valves, check valves, shuttle valves, and isolation valves. Development of these components has proven the newGeneration of 7500 psi BOP Control System is a viable solution for the newgeneration of 20,000 psi (20 ksi) BOP Systems.

Significance of Subject Matter
The 7500 psi control system supply allows Emergency Systems such as the Casingand Blind Shear Rams capable of shearing pipe at demands approaching 5000 psiwhich would be prohibited by 5000 psi systems. The 7500 psi Control Systemgreatly reduces the number of accumulators needed for surface and subsea highpressure control fluid storage when compared to 5000 psi control systems.

Background
The industry has been drilling high pressure and high temperature (HPHT) wellson the shelf and in deepwater Gulf of Mexico (GoM) to true vertical depths ofover 30,000 feet over the last decade. The reservoir pressures exceed20,000–25,000 psi and temperatures can exceed 300°F. The mudline shut-inpressures for some of these wells approach, and in some cases exceed 15,000psi. To date, deepwater Mobil Offshore Drilling Units (MODU's) have not had thewell pressure containment equipment to complete wells where the anticipatedwellhead pressures approach or exceed 15,000 psi.
Subsea Gas-liquid Separation: Case Studies and Technology Benefits
Authors: Magi Stefano , Gassert Michael , Russo Giovanni , Argento Francesco , Margarone Michele , Citi Gianfederico 
Published: April 2012

Abstract
Recent deepwater projects are considering Subsea Gas-Liquid Separation aspotential technology to unlock oil reserves. Eni e&p is currently workingon R&D and development studies to evaluate the benefit of this technologyfor a number of representative assets in its deepwater portfolio.
The paper presents several findings of this original analysis. Case studies arerepresentative of a wide range of potential applications: from secondarytiebacks in standard deepwater depth to 1500 m water depth oil developmentapplications and heavy/difficult oil cases to condensate/gas fieldsapplications.
The results are presented with the comparisons between standard deepwaterarchitectures and configurations based on Subsea Gas-Liquid separation in termsof flowassurance strategy, field layout, capital costs and benefits for theoperators in terms of potential additional recovery and production. SubseaGas-Liquid separation may become an enabling technology for deepwaterdevelopments if oil industry is able to resolve and mitigate possible risksassociated.

INTRODUCTION
Subsea processing coupled with innovative field architectures are one of themost attractive tools currently being utilized and considered by the oil andgas industry to open new opportunities and achieve more effective exploitationof offshore fields. Every day new oil and gas reservoirs are being discoveredin unconventional and remote areas in deep and ultra-deep water, typically farfrom existing treating and storage facilities. Subsea processing technologiesare becoming faster and faster applicable options to improve technical andeconomic performance of those challenging subsea field developments, improvingthe reserves recovery and operation strategy, and, in some cases, reducing theassociated development CAPEX.
The term " subsea processing" can be defined as any treatment of the producedfluids performed on the seabed prior to reaching the offshore installation andthe conventional surface process facility. Different devices have beenqualified and installed to boost the raw wellstream, like subsea multiphasepumps and wet gas compressors. In the last ten years, technologies to separatethe gas phase from a liquid stream and produced water from hydrocarbons rapidlyevolved thanks to great efforts on qualification program and testing campaign. Moreover, a few installations of separation and boosting devices have beenachieved, presenting really encouraging results but not neglecting operationalissues they have encountered during field life.
Enhanced Subsea Safety Critical Systems
Authors: Shanks Earl F. , Pfeifer Wesley , Savage Sean , Jain Ashish 
Published: April 2012

Abstract

Description of the Material
This paper describes how the Subsea Safety Critical Systems can be enhanced toprovide greater shearing pressure and volume for the Shear Rams when being usedby the Emergency Disconnect System, EDS, Deadman System, or Autoshear System. Utilizing accumulators which can be charged to 7500 psi differential pressureallows shearing pressures to approach the full working pressure of 5000 psi forthe Shear Ram Operators. Also discussed is the development of the 7500 to 5000psi stepdown regulator and other critical system components and how this systemcan be economically installed on existing Subsea Blowout Preventer (BOP)Systems.

Application
Some Drilling Contractors presently use 6000 to 7500 psi rated accumulators onthe BOP Stack in order to precharge on the surface to greater than 5000 psi. However, with surface Hydraulic Pressure Units (HPU), rated for 5000 psi, theycannot take advantage of the full working pressure of the accumulators. Thesubsea accumulators can be supplied with 7500 psi by several means. This paperaddresses the use of a hot line or subsea intensifier to supply the fluidpressure to the subsea accumulators. The key to having 7500 psi stored in thesubsea accumulators is to have a 7500 to 5000 psi step down regulator and othercritical components rated for 7500 psi.

Results, Observations and Conclusions
The 7500 to 5000 psi regulator and critical complimentary control componentshave been designed, developed, and tested for hot line use. The Isolation andDump Sub-Plate Mounted (SPM) valves have been qualified for 7500 psi serviceand the 7500 psi check valves are in the qualification process. The subseaintensifier is under testing and the results will be presented at thepresentation.

Significance of Subject Matter
The well construction designs for wells presently required by regulatoryrequirements are requiring larger, thicker wall, and higher yield casingstrings as well as drill pipe used in drilling and landing strings. Thesegreater strength requirements are requiring greater shearing pressures for thehigh pressure Shear Rams. Utilizing 7500 psi supply allows shear pressures togo as high as 5000 psi with a reasonable number of accumulators to supply thefluid.

Background
The goal of a rig's safety critical emergency system is the ability to shearpipe and safely seal the well when circumstances dictate.
Two important aspects of Safety Critical BOP Systems are:BOP Components and ArrangementControl System Design, Operating Philosophy and Dedication ofAccumulators