Earlier this year, Shell launched a consultation to decommission the upper structure of the first of four Brent field topsides – oil drilling rig platforms. Production at Brent Delta ended in 2011, and at two other topsides in the field in 2014. That one field has produced about 10% of all UK North Sea oil and gas since its commissioning in 1976.

As the UK oil and gas industry continues to suffer from low oil prices, one might conclude that the taking away of the Brent Delta platform symbolises the plight of the entire North Sea oil and gas extraction industry: a slow, drawn-out death.

Last year was terrible for the UK Continental Shelf (UKCS). First, the price of oil fell from $100 to less than $50 a barrel in the second half of the year. At the same time, operating expenditure rose 8% to £9.6 billion and capital expenditure on new fields also rose to £14.8 billion. The inevitable net result was a negative cash flow of £5.3 billion, "the worst since the 1970s", according to industry trade body Oil & Gas UK, which published a pessimistic activity report about the current state of the North Sea industry, and its future possibilities, in February.

Its report was also negative about future development of the reserves there. First, little future investment in North Sea fields has been lined up; capital expenditure is expected to fall by a third at the end of 2015. A three-year outlook of projects for company sanction is expected to fall to £3.5 billion from £8.5 billion last year. "The basin is not generating new projects and, as a result, there is very little fresh investment."

Similarly, exploration, a necessary precondition for new drilling projects, has fallen. Last year was a typical situation: only 14 wells were drilled out of the 25 expected, according to Oil & Gas UK figures, and down from 40 in 2008. Around 10 are expected to be drilled this year.

As for drilling projects, only 10 well licences were awarded in the latest (28th) round held in November 2014, down 60% from two years before. More positively, most majors did participate, including BP, Shell, BG Group, Centrica, Total and Statoil of Norway.

The one bit of good news about 2014 was that production falls in UKCS, which seem to have been endemic since 2000, were arrested by their greatest degree since then, just a 1% loss ending at 1.42 million barrels of oil equivalent/day (of this gas is about 30%; the rest is liquid). Oil & Gas UK says this was partly due to the absence of unplanned outages, thanks to a cross-industry programme of production efficiency in existing fields, plus investment in new start-ups, courtesy of tax allowances.

The issue of tax, and government involvement in the industry more generally, was the focus of an important industry review chaired by Sir Ian Wood and published in February 2014.

Commissioned by the government in 2013, it ended up being critical of both industry and government. Among other things, it called for the establishment of a new, less bureaucratic offshore state regulator; this has since happened. The Oil and Gas Authority started work in Aberdeen on 1 April 2015, under Andy Samuel, a former BG Group executive.

Back in 2014, Wood said there are multiple challenges facing the UKCS: "The number of fields has increased to over 300; new discoveries are much smaller; many fields are marginal and very interdependent; and there is strong competition for ageing infrastructure. In short, the UKCS is now a patchwork of interconnected and interdependent operations. There is also growing competition from many international offshore regions."

So some of his recommendations include expanding industry collaboration; this might include sharing crews and support vessels. The wording of the title of his project, UKCS Maximising Recovery Review was named maximising recovery, seems to have spawned a buzzword of its own: MER, or 'maximising economic recovery'.

As the industry saw last year, cost increases, which have risen from something under £6 billion in 2003 to nearly £10 billion today, remain a big issue. This, for example, is the reason Shell gave for a second cull of North Sea staff and agency contractors, announced in March 2015. "To help secure Britain's future as a significant oil and gas producer, the industry also urgently needs to tackle the issue of rising costs," it said. Some 250 posts were cut in August 2014; "at least" that many would go this year from a total workforce of 2,400. In addition, the company has decided, in principle, to move to an even-time working shift rota, such as a three-week-on–three-week-off pattern.

However, Oil & Gas UK points out that reducing costs by 20% will only take the industry back to 2011 levels, so there is more work to be done. Its chief executive, Malcolm Webb, says: "Even at $110 per barrel, the ability of the industry to realise the full potential of the UK's oil and gas resource was hamstrung by escalating costs, an unsustainably heavy tax burden and inappropriate regulation. At current oil prices, we now see the consequences only too clearly. The industry recognises that its cost base is unsustainable. Cost and efficiency improvements of up to 40% are required to give this basin a viable future. This adjustment is now underway, but cost control alone is not the answer."

Oil & Gas UK says that efforts are needed not only to reduce costs but also to improve regulation and tax incentives to make the area more attractive to investors. It estimates £94 billion of investment is required to recover the 10 billion boe that is both sanctioned in company plans and unsanctioned potential opportunities.

Surely the investment environment will benefit from the actions of one oil and gas major at least, BP, which said in April that the North Sea is an "important" region for it, and that it expects to sustain a significant business here for the long term.


A new semi-submersible, Deepsea Aberdeen, has begun a seven-year drilling programme in oil and gas fields west of Shetland on the UK Continental Shelf, organised by the Schiehallion consortium of BP, Shell and oil and gas exploration company OMV. That field and the nearby Loyal field have produced nearly 400 million barrels of oil since production started in 1998. In July 2011, BP and partners announced their intention to invest around £3 billion to re-develop the Schiehallion and Loyal fields as part of the Quad 204 project to access the remaining estimated 450 million boe of resource still available and help extend production from the fields out to 2035 and beyond.

The development involves the installation of a new floating production, storage and offloading (FPSO) vessel – the Glen Lyon – due to arrive in the North Sea in 2016, together with a major upgrade and replacement of the subsea facilities. Production was suspended in 2013 to make way for Quad 204 subsea works.

Glen Lyon, which measures 270 m long by 52 m wide, will be able to process and export up to 130,000 barrels of oil a day and store up to 1 million barrels.

Operated by Odfjell Drilling, the Deepsea Aberdeen will initially drill two producer wells and one injector well on Loyal, before moving onto Schiehallion to continue its activities. Five wells are planned prior to first oil from Glen Lyon at the end of 2016.

- In January, gas and condensate production from the Total-operated West Franklin field in the UK North Sea began. The field is due to deliver production of 40,000 barrels equivalent a day gross when fully commissioned. With reservoir pressures in excess of 1,000 bar and temperatures in excess of 200 °C, the project has advanced the boundaries of existing high pressure, high temperature technical know-how in the industry. BG Group has a 14% stake in West Franklin; Total has 46.2%.

The Petrojarl Knarr floating production vessel began production in the Norwegian North Sea in March (Photo: BG Group)


- In March, the Petrojarl Knarr floating production, storage and offloading (FPSO) vessel had started production from the Knarr oil field in the North Sea, offshore of Norway. The FPSO is moored approximately 75 miles off the Norwegian coast and has a production capacity of 63,000 boe per day. The Knarr field, discovered in 2008, has estimated gross recoverable reserves of around 80 million boe with a production life of at least 10 years. New exploration drilling in the licence area is ongoing, in order to help extend the production life further. BG Group is the operator of the field, having a 45% working interest; other partners include Idemitsu Petroleum Norge (25%), Wintershall Norge (20%) and DEA Norge (10%).

- The installation of the modules that collectively constitute the Statoil Åsgard subsea gas compression system has commenced on the Åsgard field, one of the largest in Norwegian waters. Gas compression provides the driving force necessary to ensure a high gas flow and level of extraction. Innovative technology at a depth of 300 m will create 282 million extra barrels from the Åsgard field. A total of 22 modules will be installed and connected this summer. This is the first time Statoil has employed compression on the seabed, rather than on a platform; it claims that the technology represents a quantum leap in the level of extraction and operational life of a number of gas fields. Subsea processing, and gas compression in particular, is an important technology for developing fields in deep water and in exposed areas.

- Norway's Statoil recently signed a construction contract with Kvaerner and KBR for a utility platform and living quarters for 560 people on a new field, Johan Sverdrup, on the Norwegian continental shelf 100 miles west of Stavanger. It is scheduled to start up in 2019. At its peak, the field, discovered in 2011, will account for 25% of all Norwegian oil and gas production; it is one of the top five largest discoveries there. Statoil calls it "one of the most important industrial projects in Norway over the next 50 years". The ambition is a recovery rate of 70% of 1.4-2.4 billion boe. The Johan Sverdrup licencees are Statoil, Lundin Norway, Petoro, Det norske oljeselskap and Maersk Oil. The partners have recommended Statoil as operator for all field phases. First-phase investment is NOK117 billion (£9.8 billion).