Can technology save the UKCS?
The role of composite pipe as part of a cost saving drive to bring the UKCS back to profitability
Subsea production might have been born in the Gulf of Mexico (GoM) and Brazil before the 1980s, but it was in the UK North Sea sector that it grew from infancy to maturity.
The British sector has not been short of ambition, adventure, enthusiasm and risk-taking, and the North Sea was where it was at as far as subsea technology went, at least until the expansion into West Africa since 2000. This began with the Shell/Esso Underwater Manifold Centre and carried on with shallow-water projects by Amerada Hess, then by BP west of the Shetlands beyond 400 m (1,312 ft) and Chevron’s recent Alder HPHT 28-km (17-mile) subsea tieback. Scroll forward to the present, and what is found today is a British offshore sector in a major funk.
- Total expenditure on the UKCS decreased from £26.6bn in 2014 to £19bn in 2016
- UKCS capital investment fell to £9bn in 2016 from a record £14.8bn in 2014
- The UKCS generated a free cash-flow deficit of £2.7bn in 2016 (Oil & Gas UK)
- Average rate of return for extraction companies on capital investment in Q1 2016 was just 0.2% vs 50% in Q1 2011
The oil price crash of late 2014 has had much to do with UKCS woes, but there are other significant factors as well. The North Sea sector has long been known as a high cost location, both for capex and opex, with years of underinvestment in exploration by majors hunting elsewhere in the world, leaving the sector with a portfolio of around 350 minifields that will require clever thinking to develop.
The price crash finally focused everyone’s attention on what was needed: a sector- wide analysis undertaken by Sir Ian Wood in 2013 and presented in February 2014. This review added a new phrase to the offshore lexicon – ‘maximum economic recovery’- and sent the UK down a path it had never been before, trying to save the offshore sector.
In parallel with this localised approach, there had been an urgent industry drive to reduce costs. This was a process that had actually begun before the crash, going back to the early part of 2013 with operators already applying the brakes to big deepwater projects.
For example, BP’s original scheme for Mad Dog 2 expansion in the GoM put forward in 2013 had a price tag of $20 billion. No way, said management, go back and look again. So it did, and the development scheme, described as more standardized, was sanctioned at the beginning of December last year with a price tag of $9 billion.
BP would like to take most of the credit for this major capex reduction, which it said is due to a less expensive semisubmersible floating production system, and it certainly deserves some plaudits. However, it also had the opportunity to re-tender the whole project at a time when there was a dearth of big projects going ahead, and could have benefited from general cost reduction in equipment and services across the industry.
Wood report recommendations and studies
Harte Energy has looked back at the Wood report to see which recommendations have come to fruition. One of these was the creation of a new industry regulator and some at the time expressed wonderment at how a new regulatory body could make a difference to the future of the sector. However, the recent work the Oil & Gas Authority (OGA) has undertaken has already proved many critics wrong already.
If the future of the UK sector is to be based on the portfolio of marginal fields (those with less than 50 MMboe in reserves), a significant majority, about 200, will be developed as tiebacks to existing infrastructure. Many, and possibly most, will also be developed using subsea wells.
The OGA already has taken on board the need to ensure that the right technology is available to all operators. In what must have been an unprecedented action by a UK regulator, it commissioned four studies to determine the economic viability of fields that might make use of specific technology and what the impact might be. There seems to have been some collaboration between OGA and Oil & Gas UK’s Efficiency Task Force, the latter body which is an association of operators and main contractors.
Two studies involved looking at conventional subsea tiebacks and making use of already proven but less expensive pipeline tie-in technology, which produced savings of 18% to 28% on project capex. Some of the technologies identified as applicable in such cases are mechanical rather than welded hot taps, mechanical connectors as an alternative to welded pipe and spooled pipelines and composite pipe such as m-pipe® offered by Magma Global.
Other studies also looked at riser systems for FPSO units and a different configuration of pipeline bundles with integral manifolds, where savings of 15% to 25% are suggested.
OGA has also looked at and identified other technologies that might be applicable for low-cost standalone developments, which represent nearly one-third (120) of the marginal fields. Some of the options include:
- Mini-FPSO units
- Unmanned production buoys
- Subsea storage to eliminate long pipeline tiebacks
- Subsea factories with seabed processing prior to export
The challenge of cluster development
OGA has also analysed the marginal field portfolio and developed a strategy based on field location, and proximity to infrastructure and to other finds. It also has looked at some specific clusters to see how they might be developed. Already analysed is the West Sole Catchment Area in the UK’s Southern North Sea Gas Basin, with combined proven reserves of at least 14 Bcm (500 Bcf). This cluster includes Centrica’s Olympus discovery, Dana Petroleum’s Platypus find, two small Premier fields and one held by Hansa Petroleum plus one relinquished find (Glein West) and at least six other prospects.
One challenge that often has reared its head in the sector is alignment of development priorities. This cluster, for example, has four operators and 11 licensees, some of them small. Trying to get this group to agree to a development scenario, timetable and program is not an easy task. One advantage that OGA has is control of licenses. To make this cluster more economic, it could throw the relinquished find into the mix to benefit the entire development.
The impact of the UK Oil & Gas Technology Centre
Bolstering OGA’s enterprise was the formal launch in February of the Oil & Gas Technology Centre (OGTC) in the U.K. One of its first tasks is its ‘small pools’ initiative, which is running parallel to the work on marginal fields. Even before the launch OGTC’s team had thrown down the gauntlet by declaring that it is aiming to eliminate stranded assets by 2025, a rather bold declaration.
Two of the technologies that are at the top of its wish list involve gas handling and umbilical-less subsea systems. Disposal of associated gas that comes with small oil finds has often in the past been a major roadblock to development as the options are either environmentally or economically unpalatable. This includes flaring in the case of an FPSO unit or small platform or drilling a gas disposal well as part of a subsea development.
As for eliminating the umbilical from the subsea system, this has been a desire for decades, but throughwater communications has a number of limitations that to date have not been overcome. It has even been suggested that technology developed for the military could be made available, such as that used with permanently deployed sensors on the seabed to track submarines, but this is a challenge that will test the mettle of both engineers and regulators.
New Technology has a clear part to play in any new subsea developments, helping to reduce Capex required in tie-backs and their subsea deployment.
Whether the oil and gas industry has the mettle or bravery to grasp qualified and proven new technologies like thermoplastic composite pipe to reduce Capex and Opex in the short term remains to be seen. But, along with other new technologies, composite pipe could become a key part of the hope and future of the UK’s North Sea in the next decade, reducing whole-life maintenance costs due to better performance against sour fluids and corrosion and delivering increased subsea longevity.
This blog is based on an article first published in EPmag.com in April 2017. To read more click here