The £2.5billion Laggan-Tormore project on the UK Atlantic Frontier has finally been approved and should, once onstream, deliver some 1trillion cu ft of gas to the UK market, plus significant volumes of condensate internationally, starting in 2014.
In 1986, the partnership of Shell with Britoil drilled a well 200km (125 miles) north-west of Shetland in 600m (1,968ft) of water. Hoping for oil, they instead found a gas-condensate reservoir.
As a result, 206/1-2 was destined to become one of a number of gas/liquids finds made on the UK Atlantic Frontier that became moribund due to a perceived lack of scale, coupled with technology challenges deemed too hard to handle at the time.
That particular acreage was to be relinquished back to the UK Government.
About 10 years later, the licence on which 206/1-2 was drilled was back in the Government’s North Sea lotto – the 16th Oil & Gas Round of 1995 in which Total was awarded the acreage as the French group felt there was latent potential.
Total proceeded to drill three further Laggan wells – 206/1-3 in 1996 to get a better initial feel, then 206/1a-4a and the 206/1a-4aZ sidetrack of 2004, which was suspended as a possible future producer, albeit against ongoing worries about commercial viability.
The 206/1a-4aZ well tested at 37.8million cu ft per day of gas. Work continued on a potentially stand-alone development if the economics could be made to work.
Doubts were, however, assuaged with the 205/5a-1 success when Laggan consort Tormore was found in 2007. Total at last had, with little doubt, a viable project in the making.
Driving the dream forward during its early years under Total was the French group’s UK North Sea chief, Michel Contie, who was passionate about the UK Atlantic Frontier, who wanted to see a commercial gas breakthrough in the sector and who lobbied and lobbied the UK Government in a bid to persuade it to make a strategic investment in gas transportation infrastructure.
Contie was undoubtedly also an important catalyst to the eventual creation of the West of Shetland Task Force (WoSTF) between the industry and the UK Government.
Until Laggan-Tormore is brought onstream, for now, UK Atlantic Frontier gas export infrastructure is limited to the BP-operated 20in West of Shetland Pipeline System and the East of Shetland Pipeline System which, together, transport associated gas from Clair and the Schiehallion/Foinaven fields to BP’s Magnus platform in the East Shetland Basin for enhanced oil recovery. However, this pipeline routing is limited in capacity and commercially complex.
So what of the reservoirs and the development plan?
Laggan is a Palaeocene gas condensate accumulation and the reservoir is a combination structural/stratigraphic trap.
The crest of the structure is at 3,500m (11,480ft) below the sea floor and there is a 400m (1,312ft) gas column. The reservoir covers an area of about 42sq km. The total gross reservoir thickness (T35 sands) is less than 70m (230ft), including two field-wide inter-bedded shales. The reservoir comprises sand-rich turbidite lobe facies, with the reservoir architecture controlled by compensation and normal faults.
Tormore is similar to Laggan in terms of trapping configuration, depositional model and reservoir properties. The main difference is the fluid, with Tormore gas condensate being about three times richer than Laggan – a big plus.
The reservoir lies at a depth of 5,505m (18,060ft) (crest).
The fact that Tormore is richer than Laggan is of considerable commercial importance. It is located some 16km (10 miles) south-west of its neighbour and had, for some years, been recognised as a potential gas resource by the licence partners.
In parallel to the activities of the WoSTF, the Tormore partners put together a plan to drill the prospect in summer 2007 using the Sedco 714 semi-submersible.
The well was spudded on June 13, 2007, in 610m (2,000ft) water depth, with total depth reached in less than two months, on August 3. After final logging, a drill-stem test was performed.
According to a paper prepared for the Society of Petroleum Engineers by Total, the discovery in Tormore of appreciable further quantities of gas condensate close to Laggan brought a welcome boost to the WoSTF and “put the ball firmly back in the court for the Laggan-Tormore partners to push forward with their plans to open up a new gas export infrastructure for the region”.
After preliminary studies confirmed the potential economic value of a combined project, the partnership agreed to move forward with an aggressive schedule of development studies aimed at selecting the optimum development concept by mid-2008.
Departing from the conventional sequence of conceptual studies followed by pre-project, it was agreed to update the original stand-alone Laggan pre-project to take account of Tormore while, in parallel, running an offshore hub conceptual study.
A range of options were considered:
Onshore hub: a long-distance subsea tie-back to a new onshore gas-processing plant close to the existing BP-operated terminal at Sullom Voe.
Shallow water hub: a subsea tie-back to a new platform in 150m (492ft) water depth on the shelf close to the existing BP-operated Clair platform.
Deepwater hub: a subsea or dry tree tie-back to a floating TLP (tension-leg platform) or deep draft semi-submersible moored in 600m (1,968ft) close to the sister fields.
According to the SPE paper, the later inclusion of the Tormore field did not have a significant effect on the findings of the earlier environmental screening studies.
In the event, the decision was made to develop Laggan-Tormore based on a subsea package offshore, tied back via two multiphase flowlines to a shore-based processing plant located at Sullom Voe, in Shetland.
A subsea tie-back to shore, with all operations staff being shore-based, is safest for people working on the operational phase of the project; it provides access for third parties to the regional gas-transportation system, and a subsea tie-back to shore, with the addition of subsea compression in late field life, will allow maximum recovery of reserves.
There is also the issue of the physical environment – another good reason why the subsea/onshore approach was selected. The water-current patterns in the vicinity of the sister fields are complex, with various strong non-tidal currents interacting with relatively weak tidal flow.
On the surface, the deep water over the West of Shetland continental slope is exposed to a large oceanic fetch and strong winds, particularly from the west and south-west. These conditions can generate an extreme wave regime that is more severe than that experienced in the Northern North Sea. The area is also affected by long periods of ocean swells generated by Atlantic storms.
It is planned that drilling operations at Laggan-Tormore will be carried out in two phases.
To facilitate this, a six-slot template-manifold will be located on the seabed at each of the Laggan and Tormore locations. Deviated wells will be drilled from the central template to the reservoir targets and use may be made of a suspended well close to each of the templates.
Under phase one (2012-14), three new wells are planned at Laggan, plus re-entry of one of the existing wells, together with one new well plus possible re-entry of an existing well at Tormore.
Under phase two (2015), two additional wells (one per field) are currently planned, with well siting optimised following the review of year-one production data. A contingency of two additional wells is allowed for in the project in the event that existing wells are found to be unsuitable.
The subsea wells will be controlled via an electrohydraulic umbilical, which will include cores for the transport and injection of chemicals (scale, corrosion and wax inhibitor) as well as methanol for start-up purposes.
Dehydrated gas will be exported to the St Fergus gas terminal via a 225km (140-mile, 30in new-build gas pipeline, with a subsea tie-in to the existing Total FUKA gas pipeline close to the decommissioned MCP-01 platform.
Condensate will be separated from the gas during processing at the new Shetland facility, then stabilised and exported by tanker from existing BP facilities at Sullom Voe.
The proposed Laggan-Tormore Gas Production Plant (GPP) will be designed to process 500million cu ft per day of gas, plus associated condensate (design rate 27,900 barrels per day).
To take account of future third-party gas production, the gas-export facilities will be sized for up to 665million cu ft per day.
Peak production rates are projected to be north of 454million cu ft (1.59million cu.m) of gas and 16,700 barrels of condensate per day in 2015.
Output is then expected to decline gradually over time through natural depletion of the reservoirs.
Total has instigated a research-and-development programme on subsea compression and its possible use on Laggan and Tormore. The company says the potential timing of installation would be around 2018. However, subsea compression is not part of the initial field development plan.
The export pipe will have a designed capacity of 665million cu ft per day, and it is anticipated that other future developments West of Shetland will subsequently tie into the line and use the additional pipeline capacity to export their gas. The Glenlivet discovery is an example.
It is potential future projects such as Glenlivet that should benefit from the UK Government’s latest measure to stimulate activity.
It was in January that the Government announced an incentive to extend the “field allowance” announced in the 2009 Budget to remote deepwater gas fields such as those found in the West of Shetland area.
The allowance could provide up to £160million worth of tax relief for each gas field in the West of Shetland region which qualifies for the support.