When Total launched the Laggan-Tormore subsea tieback, West of Shetland, it was always with the long-view, and not just in terms of distance. The investment is starting to pay off. Elaine Maslin reports.
The 143km-long gas pipeline export facilities for Laggan-Tormore, with pre-installed tie-ins points, is no ordinary subsea tieback. As well as being the UK’s longest tieback, it created a hub for further development in the area when it came onstream in 2016.
It’s already bearing fruit. Total brought the first two tie-ins to the system online ahead of schedule and 30% under budget earlier this year.
First gas had been expected from Edradour in Q4 2017, with Glenlivet expected to come onstream in late 2018. Instead, both were onstream in August this year and Total is already looking at other opportunities in the area.
West of Shetland development. Map from Total.
The advanced schedule and reduced costs were achieved by being careful not to plan or carry out drilling and construction activities in the harsh winter months, and by using much of the same subsea equipment for the latest tiebacks as it did for Laggan-Tormore, as well as the same processes and procedures, tooling and spares, says Kevin Boyne, West of Shetland asset director, Total. The drilling and project teams comprised staff and contractors (where feasible) who already had experience on Laggan-Tormore.
However, it hasn’t been a complete replica. The Glenlivet Edradour project saw the first use of seam welded pipe in a control umbilical and the use of thermally sprayed aluminium inside part of the Edradour flowline to help keep it cool, to minimize corrosion due to the CO2 content of the Edradour production.
“By careful planning, maximizing the use of the summer season and building on lessons learned from Laggan-Tormore, we were able to carry out a cost-efficient, long subsea tie-in to existing subsea infrastructure in more efficient way, significantly reducing both cost and schedule,” Boyne says.
Edradour was discovered in 2010, in 300m water depth, then tested in 2011. The field contains lean gas condensate, with about 5 mol% CO2. The initial reservoir conditions were about 118°C and 345bar. Glenlivet, in 435m water depth, was discovered in 2009, by DONG Energy (which has since exited the hydrocarbon industry) and is also lean gas condensate, but the initial reservoir conditions were lower at 65°C and 229bar.
Neither fields met Total’s investment criteria when assessed on their own merits. But, as a joint development, tied into the pre-installed in-line tees on the Laggan-Tormore system, they became economic.
The Laggan-Tormore export system comprises two, 18in, 143km-long pipelines to the onshore Shetland Gas Plant. It also has an 8in MEG injection line, 2in service line and a control umbilical, and capacity to tie-in 20 wells, eight of which have been used to date, including Glenlivet and Edradour.
|The West Phoenix. Image from Seadrill.|
For Glenlivet and Edradour, the same manifolds, Xmas trees (FMC Technologies’ 10,000psi vertical Xmas trees), pipelines, flowline end terminations, tooling and spare parts as Laggan-Tormore were used, reducing costs, and where possible facilities were shared, i.e. using a single pipeline end manifold for both fields. This ethos resulted in Glenlivet and Edradour comprising two production flowlines, which both tie into the Edradour pipeline end manifold (PLEM). One, 35km-long flowline, ties back two wells from the Glenlivet manifold, and the other, at 17km-long, ties a single well back from Edradour. A single 6in MEG line from the Edradour PLEM serves both fields, with a single umbilical serving both routed from the Laggan manifold.
Boyne says that cooperation with contractors helped. “The project was sanctioned in a high-cost environment,” he says. “Total has worked with TechnipFMC to reduce costs. They made savings and passed those on and we had good cooperation in terms of trying to reduce and simplify the scope.” This included combining a 6in MEG line with a 2in service line in a single deployment, i.e. piggy back, over the Glenlivet and Edradour lines.
Using new technologies has also brought savings. Using seam welded super duplex tubes on the Glenlivet umbilical (seamless tubes on Edradour) reduced costs. The seam welded process was developed by Vallourec with laser welding technology for longitudinal welding. The process gives pipe higher mechanical properties, with reduced wall thickness, helping to reduce umbilical weight, making handling easier.
Using thermally spayed aluminium inside the pipe also reduced costs. It was needed to help reduce temperature, as there’s a link with temperature and corrosion related to CO2 corrosion. Typically, a cooling loop is used to bring the temperature down, as well as use of corrosion inhibitor, Boyne says. Using the thermally sprayed aluminium and understanding the thermal impact of rock dumping and how much it could be reduced, by using glass-reinforced plastic covers (with rock dumping either side, instead of on the pipe) helped reduce the need for that additional equipment and chemical use.
Compressing the project execution timetable – while trying to avoid the impact of winter weather West of Shetland – also had a huge impact, bringing forward first production by over a year, in the case of Glenlivet, and savings on contingencies that didn’t have to be drawn.
With the Edradour well completed and subsea installation work carried out in 2015-2016, the plan was to install the subsea infrastructure for Glenlivet in 2017, followed by wells completion (two deviated Glenlivet wells drilled in 2015) in 2018.
Total wanted to avoid operating in winter. “In winter you have the jet stream bringing deep lows through the West of Shetland area,” Boyne adds, “With high winds and high waves.” The conditions make operations, drilling, logistics and installation activities challenging, with a high risk of waiting on weather.
But, attempting to do the drilling and installation campaigns at the same location, in one summer season, was also very challenging. However, having seen the 2015-2016 campaigns go well, with the focus on making the summer seasons (i.e. April to September) as efficient as possible, it was decided to try to advance the Glenlivet schedule.
“We looked again using the learnings from Laggan-Tormore and challenged ourselves to see if we could carry out the well completions on Glenlivet first [in early summer season 2017], then carry out installation work during the remainder of the 2017 summer season,” Boyne says. This would allow Glenlivet to start up in October 2017.
Drilling went well, starting early in the season in 2017, and the project vessels were allowed in early, with simultaneous operations procedures in place. At peak SIMOPS (simultaneous operations), the West Phoenix semisubmersible drilling rig was doing a Glenlivet upper completion while the Deep Explorer was installing flexible spools and rigid jumpers, the Far Superior was doing pre-commissioning of pipelines and the Nordnes doing rock dumping.
Then, by bringing forward commissioning and start-up activities before some of the non-critical path activities (rock dumping and installing protection structures) were completed, Edradour and Glenlivet first production were both brought forward to August.
|Deep Explorer. Photo from TechnipFMC.|
Detailed planning, good interfaces between drilling, project, operations and commissioning/start-up teams, and careful SIMOPS, to make sure everything was coordinated, were key, Boyne says. Experience within the teams, which had worked on Laggan-Tormore previously, as well as use of contractors who also had experience on Laggan-Tormore (North Atlantic Drilling and TechnipFMC), also helped significantly, Boyne adds.
The same rig, the West Phoenix, was used on Edradour and Glenlivet as Laggan-Tormore. But, Total also achieved commercial efficiencies. Total hadn’t contracted the rig for the full project, which meant costs fell from around US$450,000/d at the end of Laggan-Tormore to about $145,000/d during the 2017 season, reflecting market rates.
With Edradour and Glenlivet now online, Total is looking at what else is in the area. There are a few relatively small discoveries in the area, but also exploration prospectivity, Boyne says, pointing out that, according to the UK Oil and Gas Authority, 17% of the UK Continental Shelf’s remaining reserves could be West of Shetland area.
There are also oil fields in the area that could now have an export route for any associated gas. As well as looking at fields in its own portfolio, it’s also looking at third party business – tying in other people’s assets – and it is participating in the 30th licensing round to add to its acreage.
There’s also more potential for testing new technology. Total has said Laggan-Tormore, an electro-hydraulic system, would have been economically viable as an all-electric system. For future tie-ins that stretch beyond the potential for additional electro-hydraulic tie-ins, i.e. beyond around 150km, all electric would be a viable alternative, Boyne says, potentially still using the Laggan-Tormore pipeline system, but with electric controls.
Elaine Maslin examines the Laggan-Tormore development.
The beginning in nigh
Total assessed an all-electric system for Laggan-Tormore and has been considering subsea compression.