The London evening meeting ‘Lessons Learned from Åsgard Subsea Compression’ was a rare opportunity for SUT’s members to revisit the successful story of the groundbreaking subsea engineering project.

Iain Knight, as chairman, introduced the presentation from Marco Gabelloni, the regional manager of advanced subsea technology for Aker Solutions. Previously, in a September 2012 evening lecture Aker had outlined its plans then deep in engineering – now Marco was able to share crucial lessons learnt from the extensive development, technology qualification and operational phases of that most challenging of all major projects, the “first one-of-a-kind” now live and producing extra hydrocarbons.

Earlier studies on how to extract more resources from Åsgard in its late life concluded that deploying the compressor some 260 metres subsea had lower CAPEX and OPEX than the alternative of a dedicated compression platform whilst still affording Statoil the prize of an additional 300 million barrels of oil equivalent (BOE) recoverable. It also offered better efficiency and HSE benefits.

What then followed was serious engineering of how to deal with the multiphase well stream and integrate the totally enclosed MAN compressor with booster pumps into a modular architecture that included very stiff subsea support structure for the compressor. This ultimately required some 40 individual technology qualification programmes – no mean management challenge, especially when running during the project execution phase.

DESIGN

Some key features of the Åsgard design are: all electric variable speed control via from the host topsides; multiphase coolers; 6.6kV subsea wet connectors; maintenance-free magnetic bearings; and the ability for system deployment in up to 4.5-metre significant waves via a special handling frame.

A very prudent phased programme of testing was deemed essential given the innovative nature of the system including full-scale submerged acceptance testing of the integrated modules after their individual testing. The Åsgard system has two 11.5-megawatt compression trains in parallel with a complete third train spare kept onshore – the intent to handle any unexpected outages by a modular swaps required all modules having to be totally interchangeable thus imposing very tight tolerances upon the whole system.

Any future subsea compression project(s) will now be able to draw upon both a catalogue of qualified component technologies and enhanced knowledge of how these could be combined into a simplified, optimised design. For comparable design requirements this could be achieved with a 40% weight reduction.

Further, a well stream boosting system is now envisaged that would use more liquid tolerant compression, permitting the removal of the whole condensate boosting pump system.

LESSONS LEARNT

Key lessons learnt were summarised by Marco as: integration of core technologies; managing technology qualification; optimisation of challenging requirements; simplified testing philosophy; and early cooperation with the installation contractor.

Extensive questioning followed from the attendees regarding many aspects of the presentation, ranging from overall project duration, maintenance philosophy, VSD location, choice of magnetic bearings, future subsea compression projects and the extent of qualifications required for the next subsea compression project. The answers to this barrage yielded much knowledge transfer to the audience before Ian thanked Marco for his interesting contribution to SUT’s subsea engineering understandings.

Dr Frank Knight

The London evening meeting ‘Global Offshore Projects’ was the annual update on the state of the offshore market by Douglas-Westwood and Associates. The meeting was chaired by the SUT’s chief executive officer, Bob Allwood. Presentations started with an overview by Douglas-Westwood director Steve Robertson and continued with an economic summary by Matt Adams and a regional overview by Matt Cook.

Reasons for the continued downward pressure on the oil price were presented. A year ago, US$40 per barrel (bbl) was considered the bottom of the market. However, the economic slowdown in China, relentless OPEC output, Iran’s return to the oil supply market and the United States lifting its oil export embargo are all factors that have contributed to a further 40% slip in the oil price since 15 November 2015. Predicted demand for oil and gas, based on population/GDP growth is however rising unabated and linearly.

The low oil price has affected the industry differently. Based on share price, the hardest hit being the offshore drillers with rig oversupply problems as well as falling contract values. Oilfield equipment and subsea hardware companies have both fared better, due to pre oil-crash order backlog. However, now with little backlog left, many areas of the market will not see business above 2014 levels even by 2021. In 2013-14, the industry saw huge growth in field development activity, a knock on effect of oil at greater than US$100/bbl. This makes the current drop off in demand more pronounced – i.e., expected subsea tree installation in 2020 is half that of 2014.

REACH

Gas field development has a more positive long-term forecast than oil, it is seen as a “bridge” fuel to help reach new greener renewable energy objectives. Regionally, there are bright spots with on-going drilling and development activity. Key areas are Egypt (based on high demand for domestic gas) and Mozambique (based on the potential of its giant gas fields). Past important offshore areas now have lower outlooks. Predicted drilled wells in Angola will be 45% down in 2018-21 compared to 2014-17. Brazil’s new Offshore E&P budget is down 25% on its previous forecast.

On skills, the industry had a significant shortage in 2014; additionally, 48% of the employees were aged 45 or over. Since 2014 the industry has lost more than 250,000 jobs. The personnel will have left the industry or moved to the downstream sector. The lack of skilled workers will be a problem when the offshore market picks up. However, there are also positives if new innovation can be brought into the industry along with new faces.

Cost reduction is the order of the day with the oil companies. Most projects are undergoing revision, renegotiation, postponement and in some cases cancellation. For example, development costs for phase two of BP Mad Dog have fallen by half, from US$20billion. Standardisation within field developments is a way of reducing costs and this can initially be an opportunity for FEED companies. Lower oil price brings forward decommissioning as older fields will become non-viable faster. UKCS is a critical area with 288 platforms to be decommissioned by 2040. Most platforms, however, will remain in place until 2020.

Despite the uncertainty about when growth will return, bright spots such as offshore wind and the continued requirement of high levels offshore maintenance give some hope to the offshore technology companies.

SUPPLY

The meeting ended with questions from the audience which were focused on when the market will bottom out, and the threats to the offshore market from shale oil/gas and OPEC supply. Steve Robertson commented that there were no positive drivers for market uplift until the second half of this year. At present, Saudi Arabia is showing no signs of a production cut despite running a government 15% deficit. US interest rate raises will make it more difficult for suspended shale drillers to re-finance and restart.

Bob Allwood brought the meeting to a close and thanked the team from Douglas Westwood for their informative insight into the market.

Richard Binks