After two years of planning, BP is about to launch a major renewal program on its North Sea Magnus and ETAP facilities. BP explained the program—and its long term aims—to Elaine Maslin.
Operators in the North Sea are tackling a thorny problem— how to maintain and sustain production on facilities reaching or past their design lives. Industry initiatives, through the Health & Safety Executive (HSE), government/industry group PILOT and Oil & Gas UK, have focused on overdue safety critical maintenance, hydrocarbon leaks, and maintenance backlogs.
Image: BP's Magnus platform, photographed by Return to Scene.
Now, attention is falling on production efficiency. According to Oil & Gas UK (O&G UK), in 2011 (the latest available data), North Sea production efficiency fell to 63%, compared to about 80% in 2004. O&G UK expects this to fall again to 60% in 2012.
The difficulties facing operators are underlying integrity and reliability issues, and large workscopes, due to the age of facilities, with limited bed space available (persons on board or POB) for staff to carry out the work.
The discovery of additional resources is also extending the lives of these assets, further increasing offshore scope, and demand for bed space.
Enrique Sandoval, program manager, is leading BP’s North Sea renewal program. This is a multiyear multi-billion dollar investment across BP’s UK sector fixed platforms, so far including Magnus and ETAP.
Image: Enrique Sandoval.
“If we continue at the current pace, we will not be able to catch up and plant operating efficiency (OE) will decline, leading to the need for a big intervention,” he says.
“That means a lot of people on offshore facilities, without disrupting operations; shutting-in a field for a year is not necessarily a prudent decision. Renewal is finding a way of maintaining production, but significantly increasing the amount of work that can be done offshore.” What BP is doing BP’s renewal program will address integrity and reliability and, ultimately, establish a more sustainable operating model (SOM). Work on the renewal program started in 2011, with an overall review of the issues and opportunities across all BP’s North Sea assets.
Magnus and the Eastern Trough Area Project (ETAP) are the first two assets identified for the program, starting with the Magnus Life Extension Project (MLXP), with work scheduled to start in 1Q 2014.
Image: The Cosl Rival flotel.
The appraisal phase for the ETAP Life Extension Project (ELXP) started in late 2012. The project team is currently evaluating potential vessels that could be used to deliver the project, mid 2015.
Appraisal of Clair, a third North Sea asset, will start in 4Q, this year. The renewal program will be carried out through: specific interventions, to give a short term increase in engineering and POB capacity, to enable fabric maintenance work offshore and improvements in business processes, to reduce the requirement for work, and to increase the work that can be delivered within the POB constraints.
An accommodation vessel will be used, with flotel, jackup, and walkto- work options available. Additional work will help increase production, through well servicing, drilling, and OE improvement modification/maintenance, to be performed prior to, during, and/or following the campaign. To establish a SOM, work will also be carried out to address specific issues, such as valve procurement and management and efficient maintenance of rotating equipment.
Magnus Life Extension Project (MLXP)
Magnus was discovered in 1974. It is in 186m water depth in block 211/12, 160km northeast of the Shetland Island.
It had 1.6billion bbls initially in place and has been producing for 29 years, with peak production in 1990, at 176,000 b/d, 12,000 b/d gas condensate and 60MMcf/d gas. It has an estimated 900MM bbls recoverable and 500Bcf gas. BP’s estimated cessation of production date is currently 2027.
The facility comprises a central, conventional-steel, combined drilling and production platform, with 190 beds. The field contains a number of subsea producing wells.
Gas export is via pipeline to the Brent Alpha platform. Oil is exported via a pipeline to the Ninian Central platform.
Intervention
The MLXP workscope is non-shutdown- dependent and is mainly fabric maintenance, modification projects, and general maintenance.
The scope will use 143 POB, over and above the existing core crew, working a 24-hour day over 12 months (totaling circa 500,000 productive man-hours). About 30% of the extra 143 POB will be “green hats” initially, requiring close supervision—strict processes of control of work (CoW) and simultaneous operations (SIMOPS) will be followed.
Image: The Magnus platform
The increased staffing requires a flotel alongside, to allow for 450 POB in field at a time, increased helicopter operations, and additional attendant vessel operations.
BP will use the 1976-built semisubmersible flotel COSL Rival, with a maximum 400 POB, expected to arrive in field in Q1 2014, and remain at Magnus for 12-13 months.
Drilling operations will be paused during the campaign to simplify management and interfaces.
The three main projects included in the intervention are: accommodation refurbishment; drilling upgrades, which consist of a blowout preventer (BOP) controls upgrade, BOP crane upgrade, cooling upgrades; crane replacement, and boom rest change out.
Sandavol says: “The main challenges will be the readiness in an extremely busy environment; live-operations environment; aligning and integrating BP and contractor workforces, on and offshore; sourcing, attracting, training, mobilizing, and retaining a safe and efficient offshore team; minimizing non-productive time and improving productivity in all offshore activities; and scope prioritization and control of change.
“The renewal program, with all the life extension projects within it, will need a lot of technical people,” he says. “As we are not building any more beds, we will need to make sure all the bed space is used optimally.” The MLXP will also introduce new technology to improve operational efficiency.
BP is using R2S, developed by Aberdeen-based Return To Scene, an asset integrity and management tool using spherical photography—a visualization technology to provide a video of all areas of the platform—to create a “walk through” visual record of the facility. This can be used to view job sites, carry out initial access surveys, and allow personnel to familiarize themselves with key areas, without having to make a visit offshore. The tool also reduces costs by enabling improved planning efficiency— for installation of scaffold, for example—communication and project management.
A number of other technology options are being considered to reduce the execution time to do work (painting and inspection techniques).
ETAP Life Extension Project (ELXP)
ETAP started production in 1998. It is in 95m water depth in blocks 22/24a and 22/24b, 240km east of Aberdeen in the central North Sea.
It is an integrated development of nine oil and gas reservoirs, with six fields operated by BP and three operated by Shell/Esso.
Image: Inside the R2S system.
It is currently the largest producer for BP in the UK and Norwegian North Sea region. It is also one of BP Group’s top 15 fields, in terms of value. Peak production was in 2000, at 217,000b/d and 360MMcf/d gas. Its expected field life was 20 years, but continued reservoir delivery has led to potentially extending the economic life of the asset to 2030.
The ETAP central processing facility (CPF) comprises a production drilling riser platform, bridge-linked to a quarters and utilities (QU) platform, with a capacity for 117 POB. A normally unmanned installation, with maximum 12 POB, stands about 20km to the east.
Oil is exported via the Forties pipeline system to Kinneil. Gas is exported via the CATS pipeline to Teesside.
Sandavol says OE of the ETAP facilities has been significantly impacted by underlying reliability issues. The asset is also aging, compounding the performance decline, and contributing to an overall decline in operating efficiency.
Intervention
The ELXP’s main aim is to restore ETAP’s operating efficiency and develop a SOM. The ELXP will include adding a new accommodation facility, to increase bed space by a minimum of 25 new beds.
In total, BP expects the project to spend about 400,000 direct manhours, mostly on fabric and equipment maintenance-related work, with some like-for-like replacement of operating equipment.
The ELXP intervention will use a mobile accommodation unit alongside the QU platform, to provide access to the CPF, and support 24-hour manning. An option for an accommodation vessel has been identified.
Crucial to the entire program is planning, says Sandoval:
“We started in 2011 and will only begin work on Magnus in early 2014,” he says. “It takes roughly three years to plan properly—to identify what the right work is, then how to do it around [a] live plant.”
The team has learned from work on the ongoing Andrew Area Development, which is using a flotel to aid processing facility modifications on the North Sea Andrew platform, as part of work to tie-in the Kinnoull oil field. However, in Andrew’s case, the platform has been shut down.
SOM projects
The next challenge is to achieve a sustainable operating mode on the facilities.
“What has happened before is we, as an industry, keep doing the same thing again and again, and expect different results,” says Sandoval. “We cannot keep doing this, we need to find ways of doing things offshore differently. This is where we need technology, such as R2S.
“We also need to revisit how we work,” he says. Specifically, he wants to look at how job functions could be more flexible, so that one bed space occupant could fulfil multiple roles, instead of working in silos.
Image: The ETAP platform
A program with the SOM appraisal work will look at technology use, organizational structure, recruitment and reward strategy, leadership capability, roles and responsibilities definition, and clarification.
Sandoval also thinks more can be done in specific areas to realize a SOM, such as valve maintenance and procurement, rotating equipment, and controls and instrumentation, which can then be duplicated geographically. “There are tens of thousands of valves offshore and they are crucial,” he says. “Production losses can be down to valves. We decided how to look in to that common equipment type.
“How do we define what valves we use, how we buy them, how we get contractors in place, and how we make sure there are enough suppliers in place? Also, how do we then manage how we operate and maintain them in a consistent way?
“This is not about fixing specific equipment issues, but about creating a systematic model that identifies and proactively fixed gaps in the processes and systems to enable a long-term solution, minimizing overall production losses and increasing reliability in the long term,” says Sandoval.
In addition, SOM projects will look at right-sizing and technical suitability of facilities and aspects of obsolescence.
SOM work will also move into looking at the effectiveness of root-cause failure analysis, risk and vulnerability management, personnel issues, and plant criticality.
Together, these initiatives aim not only to renew the Magnus, ETAP, and other North Sea facilities, but also to find better ways to maintain and sustain facilities’ OE improvements and service requirements, following a flotel or any other vessel intervention. OE
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