In the Crosshairs: Cost Inefficiencies in North Sea Decommissioning
A panel of UK government officials and industry executives discuss opportunities to increase efficiency in North Sea decommissioning programs.
Decommissioning costs in the UK North Sea have become a serious issue for companies with aging fields in the region. In December, Oil and Gas UK predicted that GBP 17.6 billion will be spent on decommissioning from 2016 to 2025, with GBP 9.4 billion of that expenditure coming in the central North Sea. Over the next decade, 186 projects are forecast for decommissioning—153 in the UK and 33 in Norway—with more than 100 platforms forecast for complete or partial removal.
As decommissioning gains a larger share of industry expenditure in the region, a panel of UK government officials and industry executives gathered at the 2017 Offshore Technology Conference to speak about their strategies to managing effective decommissioning programs.
The panel discussion examined several aspects of North Sea decommissioning programs, with the importance of efficiency, cooperation, and lessons learned being common themes.
Wendy Kennedy, chief executive of the Offshore Petroleum Regulator for Environment and Decommissioning, said cooperation between the government and industry has been paramount. The UK Department of Energy and Climate Change provides companies with decommissioning guidance notes designed to help them better understand liabilities and the process for approval of decommissioning programs. Kennedy said the government regulatory agencies, the UK Oil and Gas Authority (OGA), and Oil and Gas UK review these guidance notes, and other regulations, to help make the decommissioning process more efficient for operators.
“As a regulator, we need to keep revisiting our guidance notes and our regulations and processes,” Kennedy said. “As we see decommissioning programs come through, we learn lessons from those, and we make sure to change our guidance so that it reflects good practice.”
HM Treasury, the UK’s economic and finance ministry, is also discussing the possibility of transferring the tax history of aging assets to help ease the process of purchasing fields. Decommissioning is tax deductible—companies are entitled to tax relief on the cost of plugging wells and dismantling infrastructure after ceasing production on a field—but the value of such benefits depends on the amount of tax an owner has paid during the life of an asset. If an owner company opts to decommission a field after owning it for a short period of time, it may not see noticeable relief because it has not owned the field long enough to pay a significant amount in taxes. By allowing for the acquisition of an aging field’s tax history, companies could receive credit for taxes paid by previous owners on an aging field, thus increasing its own tax benefit should it decide to cease production.
The proposal is one of several tax reform options under consideration as part of a review announced in UK Chancellor of the Exchequer Philip Hammond’s 2017 Spring Budget speech. Kennedy said that, while tax transfers are far from a guarantee, the proposal illustrates ways in which the UK government is willing to examine industry-supported solutions for easing decommissioning burdens.
“If you come into the UKCS [UK Continental Shelf] and you buy an asset, and then you decommission it, if you haven’t had 10 years of paying taxes then you have nothing to offset your tax against,” Kennedy said. “We don’t know if [tax history transfers] will happen, but I think it gives a flavor for how much enthusiasm there is for working with industry to come up with solutions that actually work.”
Dave Blackburn, senior vice president of engineering and operations at Petrofac, said the primary challenge in the relationship between industry and the OGA is aligning objectives. He said decommissioning can be a difficult area to navigate, primarily because it is not a source of revenue for owners and operators, but that there are plenty of lessons to be learned from other geographies, like the US Gulf of Mexico (GoM), that can prove valuable for North Sea operations.
Blackburn pointed to a shift away from a clear seabed strategy. In February, Shell proposed to leave in place Brent concrete gravity base structures (GBS), including the storage cells used for oil, in its plan submitted to the UK Department for Business, Energy, and Industrial Strategy. The Bravo and Delta installations each comprise 16 GBS, while the Charlie has 32. Citing its comparative assessments, the company said that leaving the contents contained in the 64 concrete GBS cells provides the best option on safety, technical and cost grounds. After removal of the attic oil and interphase material, if present, the cells will be sealed.
“There are things that we’re doing in the Gulf of Mexico that are completely different than the things we were planning to do in the UK, and some of that is now influencing the end result,” Blackburn said. “It wasn’t that long ago that people said clear seabed was the only option. We are moving from that, and that’s the sensible play. It’s not about what you do with various parts. It’s about constantly engaging and making sure we’re all working together to get the desired result.”
Win Thornton, vice president of decommissioning at BP, said the company has been particularly focused on cost inefficiencies in its projects, citing some of the steps it took with the Miller field in the central North Sea. In April 2016, BP awarded Petrofac a duty holder contract to help accelerate the late life management timeline, which Thornton said would help save costs on the project. He said BP has also worked to deconstruct its operating management system with a greater emphasis on efficiency in the supply chain.
“We tested all of that methodology with the supply chain with the Miller project, and with the down cycle that we’re in here in the oil industry, we decided to take advantage of that,” Thornton said. “I think we captured the low cycle in the marketplace and, actually, helped us get ready for the heavy-lift vessel to execute work in 2017 and 2018. We’re accelerating the decommissioning project to save costs.”
BP has already finished the first stage of the Miller program, which included well abandonment and topsides cleanup. In December 2016, the company contracted with Saipem to use a heavy-lift vessel for removal of the topsides platform and jacket.
At 17,000 tons, the Miller jacket is too heavy to be removed as a single lift. However, Thornton said that BP will seek to salvage as much of the jacket as possible—a practice he said was based on its GoM decommissioning practices—without making several hundred subsea cuts to reduce weight. The use of a heavy-lift vessel also eliminates the need for additional cargo barges, allowing the jacket removal to take place in a less restrictive weather window.
“The practice we’ve done in razing jackets in the Gulf of Mexico, where you might pick a jacket up on a hook and tow it, it’s a practice we do all the time, and it’s something we will do on the Miller jacket,” Thornton said. “We’ll pick it up, tow it on the hook and do a staged demolition. There are lessons learned from the Gulf of Mexico that we’re taking into the North Sea. There is still room for improvement, and we’ll build on these lessons learned from interaction with other projects and operators, but I think we’re on the road to success.”
Also speaking at the panel discussion were Roger Esson, chief executive at Decom North Sea, and Gunther Newcombe, operations director at the OGA.