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Challenges for Total E&P UK on the North Atlantic frontier

Energy companies are now tackling the UK's last known North Sea oil and gas province, to the west of the Shetland Islands. Jeremy Cutler of Total E&P UK explains how his company and its partners are meeting the challenges

The development of the Laggan and Tormore gas condensate fields, in the waters of the Atlantic west of the Shetland Islands, highlights the challenges in exploiting so-called "stranded" gas reserves in frontier regions far from existing infrastructure.

The region is the last known hydrocarbon province in the UK sector of the North Sea still to be developed. According to government estimates, it contains some 17% of remaining UK oil and gas reserves.

The Laggan-Tormore project - currently the UK upstream industry's largest construction project, with an estimated spend of some £2.5 billion - is the first development of its kind in this environmentally sensitive and hostile region, representing a strategic investment in deep-water gas production and onshore Shetland gas processing by operator Total E&P UK Limited and its partner Dong E&P (UK) Limited.

With co-venturers, Chevron North Sea Limited, Statoil UK Limited and OMV (UK) Limited the partnership has also invested in a new large diameter 30" gas transportation system known as the Shetland Island Regional Gas Export System (SIRGE), which opens up the west of Shetland to drilling and production for years to come. Its legacy will be a major gas transportation route from the region to the UK mainland.

Symbolic of the challenges faced by the project which, located in 600 metres of water, is a long distance subsea to beach tie-back of more than 140km, making Laggan-Tormore comparable with Norway's Snøhvit and Ormen Lange subsea tiebacks but with significantly less hydrocarbon reserves.

On plateau, the Laggan-Tormore production hub will contribute 500m cf/d of gas and 20,000 b/d of condensate. Meanwhile, the associated 30" SIRGE system has a planned capacity of 665m cf/d creating a major export route for gas from the region to the mainland at St Fergus.

The onshore Shetland Gas Plant (SGP) will bring a significant construction project to the Shetland Islands and secures the future of the islands as a major processing hub for gas and associated condensate for years to come.

Since the launch of basic engineering in early 2009 the Laggan-Tormore Project has passed the halfway mark towards first gas in mid-2014. The year ahead brings several major milestones, including the completion of the 18" and 30" pipeline scopes by Allseas, completion of the 8"/2" and umbilical installation scopes by Subsea7, installation of the SPS integrated template manifolds by Heerema and commencement of drilling by the West Phoenix.

Onshore the civil engineering works by Roadbridge to prepare the site for installation of the onshore gas plant by Petrofac are largely complete and the temporary accommodation camp is poised ready to accept more than 800 construction workers.

Long gestation

Discovered in 1986, production from Laggan has been a long time coming. Approval of the project in 2010 was the culmination of years of collaboration between industry and government to select the best technical and commercial solution for stranded gas reserves in a highly challenging environment.

The area is characterised by its extreme environment with frequent storms blowing in off the North Atlantic giving rise to large waves, strong winds and subsea currents as well as low temperatures and a short summer season for offshore installation operations.

Despite a significant exploration effort over the years by oil and gas industry operators, to date hydrocarbon production from the area has been restricted to oil and associated gas from BP's Foinaven, Schiehallion/Loyal and Clair fields. In the mid-1990s, the industry joined forces to develop a solution for so called "stranded" gas resources in the west of Shetland region. The Aurora Project, managed by Genesis Oil and Gas Consultants, concluded that several trillion cubic feet (cf) of gas reserves were needed to justify the initial investment in infrastructure to produce the gas and transport it to the market on the mainland.

In 2006, the UK government launched a joint industry partnership, the West of Shetland Task Force (WoSTF), bringing together the key operators (BP, Chevron, Dong, Exxon and Total) with hydrocarbon resources in the region. The WoSTF, led by the UK government's Department of Energy and Climate Change (DECC), evaluated a number of development concepts based around production hubs located in deep water, shallow water and onshore, close to the existing BP-operated Sullom Voe oil terminal on the Shetland Islands.

In parallel with its participation in the WoSTF, Total Exploration and Production (TEP UK) was evaluating development options for its Laggan gas condensate field located in 600 metres of water. Discovered in 1986 by Shell, Laggan was acquired by TEP UK following the 16th Licensing Round in 1995 and further appraisal drilling took place in 1996 and 2004.

The challenge facing TEP UK was the relatively small reserve base associated with Laggan and the lack of an established gas transportation pipeline system to evacuate gas from the production wells to the market entry point at St Fergus on the east coast of Scotland. In 2007, TEP UK management concluded that development of Laggan could not be sanctioned based on the very marginal economics of the field. It was decided that further exploration drilling was required to achieve the critical resource level to justify the heavy investment in gas processing and transportation infrastructure. In 2007, TEP UK successfully drilled the nearby Tormore exploration well bringing the combined reserves of Laggan and Tormore to an estimated value of 230m barrels of oil equivalent (boe).

Development challenges

Further to the discovery of Tormore in 2007 it was agreed with DECC and the WoSTF that TEP UK would launch a programme of development studies to evaluate the best development concept for the combined Laggan-Tormore gas condensate discovery.

Three generic concepts were considered:

- Deep-water Hub: based around a floating deep draft semisubmersible moored in 600 metres water depth above the gas reservoirs with subsea wells connected to the floating process facility by risers;

- Shallow Water Hub: based around a 35 km subsea tie-back to a new production platform with jacket installed in 150 metres water depth; and

- Onshore Hub: based around a 143 km subsea tie-back to a new gas processing facility situated on the Shetland Islands close to the existing Sullom Voe Oil Terminal operated by BP.

In mid-2008, TEP UK launched the Third Party Investment Process (3PIP) to investigate whether there was an appetite within the oil and gas industry to invest in the processing hub and the gas export pipeline. The outcome of 3PIP was that, whilst there was no interest to pre-invest in the gas production hub, there was interest in oversizing the gas export pipeline and increasing its capacity from 500m cf/day to 665m cf/d. As a result, the SIRGE pipeline was developed with partners Total, Dong, Chevron, Statoil and OMV.

The onshore hub concept was eventually chosen for the Laggan-Tormore development as it represented the safest option (minimising risks to personnel offshore), best economics (lowest capital expenditure and operational expenditure) and was the concept that offered the greatest flexibility for expansion (as the process facilities were onshore).

Having taken the decision on the development concept in late 2008, the key challenge remaining for TEP UK and Dong was how to maximise the value of the modest reserve base of 230m boe.

Laggan-Tormore represents one of the longest subsea to beach tie-backs in the world, equal with Norway's Snøhvit development. Figure 3 compares Laggan-Tormore with other subsea tie-backs as a function of step out distance, water depth and reserves. What is immediately apparent is that Laggan-Tormore has a very small reserve base compared to its Norwegian counterparts Ormen Lange and Snøhvit. From an economic standpoint, this means the success of the development is heavily dependent on delivering the project on schedule (first gas mid-2014) and within budget.

The management of TEP UK and Dong have been clear that the economic justification for and sanction of the project could only be made on the basis of the reserves within the Laggan and Tormore reservoirs. Whilst every effort would be made to ensure that the infrastructure could be adapted to facilitate the development of other marginal gas fields in the area, the economic evaluation would be based on the total cost of the development and the reserves in Laggan and Tormore alone. Any upside from the transportation of other third party gas fields or the future development of equity gas could not be guaranteed and therefore could not affect the initial investment decision.

The Laggan-Tormore production facilities were designed with several features to promote the later use by other marginal gas fields in the region. These can be described as follows:

- Provision of hot tap tees in the 18" import flowlines: 3 x 10" barred tees have been provided in diver depth on each of the 18" flowlines to facilitate the later tie-in of satellite fields;

- Provision of valved tees close to the Edradour discovery: 2 x 10" valved tees have been provided in deeper water to facilitate the later tieback and connection by ROV of the Edradour gas discovery;

- Provision of valved tees at the Laggan inline tee (ILT) and Tormore flowline end termination (FLET): a 10" valved tie-in tee has been included on each of the 2 x ILTs and 2 x FLETs to facilitate the potential later tie-back of extensions to the Laggan and Tormore fields and/or the installation of subsea compression to extend the production life and increase overall recovery;

- Onshore gas processing facilities: the location of the gas condensate processing hub onshore rather than offshore means that modifications to the facilities can be made more easily without concerns for overloading the supporting jacket or floating hull of an offshore production platform; and

- Provision of tie-in tees onshore and offshore for the SIRGE gas export pipeline: a tie-in point is located onshore at the Shetland Gas Plant facilities as well as 2 x 12" barred tees offshore to allow processed gas to be tied in to the SIRGE pipeline.

Sensitive environment

The environment, in terms not just of the wind, waves and currents, but also the diverse wildlife present, represents one of the key challenges to any project operating west of Shetland. The waters surrounding the import and export pipelines are home to large populations of seals, dolphins, otters, whales and sea trout. Many of the inhabitants are protected species and several Special Areas of Conservation lie on the pipeline routes, protecting species such as the horse mussel (Modiolus modiolus). The project team has worked closely with local organisations such as the Shetland Islands Council (SIC) and Scottish Natural Heritage, as well as local wildlife experts, to ensure that protected species are disturbed as little as possible during the installation of the pipelines. In addition the timings of all works has been meticulously planned to ensure we do not disturb wildlife during the breeding seasons.

The creation of a major gas evacuation route serving the west of Shetland region has acted as a catalyst for renewed exploration drilling in the region with some notable recent success by several operators. The future looks bright, as the region looks set to establish itself as a major hydrocarbon-producing province.

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