Southern comfort for UK gas men

Meg Chesshyre
Friday, April 1, 2011

A more optimistic view of the future of the southern North Sea gas and the hard-pressed East of England offshore supply chain emerged at a recent regional conference in Norwich. Meg Chesshyre reports.

Having acquired assets from BP, Shell and BG in 2003 and ExxonMobil fields in 2007, Perenco is now one of the biggest operators in the southern North Sea (SNS) and looking for future growth, the company's UK operations manager John Sewell told the East of England Energy Group's (EEEGR) annual conference. Perenco assets produce 17.5% of total SNS gas deliveries and 5.3% of total UK gas deliveries.

Perenco assets in the region range from new to 43 years old and today include 18 fields, 31 platforms, 210 wells (16 subsea), 1600km of subsea pipework, plus a gas terminal at Bacton. Current gas production is 250mmcf/d (42,000boe/d), and the spend last year was almost £125 million.

‘In our seven years of operation in the UK we have transformed the way that the operation is managed and we will continue to look for future opportunities,' said Sewell, adding that the company's expertise lies in extending field life of acquired assets.

‘It's about looking at the assets and seeing if we can operate them in a different way,' he added. ‘We need to identify mature drilling prospects.' According to Sewell, Perenco hopes to drill three wells this year, on Leman, Inde and Tyne. The company is also upgrading facilities at Bacton and offshore compression facilities, and investing a couple of million pounds this year on automatic foam injection.

He showed an overview of how Perenco has moved the end of field life out for its assets substantially compared with estimates by previous operators. He said that the overview was pessimistic in that it was based on a gas price of only £0.35 a therm, and did not allow for further investment.

‘We are tough to deal with and will challenge conventional ways of doing things, but it is that challenge that enables us to reduce the cost base and help to extend those field lives.' Some of the assets are around 45 years old, he pointed out. ‘If we look at extending those lives by another 20 to 25 years, we're talking of assets being almost 70 years old and still in production.' Those assets originally had a design life of 25 years.

On the decommissioning side, the Welland platform was removed in January using a sheerlegs-type barge – the Rambiz – with twin A-frames, a Dutch approach Sewell felt could be helpful in bringing down future UKCS decommissioning costs (see page 99). The topsides are currently being refurbished in Holland for reuse by Perenco offshore Cameroon. He made the point that although local service companies were involved in this job, the bulk of the expenditure went outside the UK ‘simply because we have not at this stage got the appropriate decommissioning facilities and expertise in the SNS'.

In the aftermath of the Deepwater Horizon incident, Sewell expressed concern that the UK was moving away from a goal-setting legislative regime to a more prescriptive system. ‘I think, as an industry, we have to fight that,' he urged. As an example, he cited the Civil Aviation Authority's requirement, with support from the Health & Safety Executive, that automatic fire-fighting systems be installed on not normally manned installations. This requirement was not based on risk management principles, he added.

Production push
Making the case for gas, Rob Nibbelke, Shell's Bacton gas plant manager, quoted International Energy Agency estimates of 250 years global supply at current production levels. Gas reserves at the moment were much larger than a few years back because of the unconventional gas growth. By around 2025 around 50% of gas production would have to come from fields that still need to be developed. Around $230 billion/year needed to be invested in the gas supply chain, he said. Wind power is intermittent so gas is the cheapest and most flexible back-up.

Shell is well positioned in the gas market, having been investing significantly in gas over the years. In 2012 it would produce more gas than oil on an energy equivalent basis. He gave two examples of significant technological developments being made by Shell. One was the 30+ years gas to liquids programme culminating in the 140,000b/d Pearl Qatar plant now nearing completion. The other was the floating LNG plant currently being designed with an eye to deployment on the Prelude field offshore Australia. At 480m long, 75m wide and weighing 600,000t fully loaded, this would be the largest floating structure ever built, he noted. It has a generic envelope, and can be re-used once a particular gas reservoir has been depleted.

Nibbelke pointed out that Shell's Bacton plant was a major gas hub, supplying 2.5bcf on a typical day – or about 20% of UK gas – from Leman, Greater Sole Pit and Sean in the southern North Sea; from Shearwater, Elgin, Franklin in the central North Sea through Shearwater Elgin Area Line (Seal)), and through the Balgzand Bacton line from the Netherlands.

‘Shell sees a very bright future in the southern North Sea and also a long-term future,' he stressed. The company is embarking on an intensive investment programme at the Bacton plant to 2014, and also on the offshore facilities.

Southern success
Some 30% of the UK's future gas reserves still reside in the southern North Sea, Paul Lafferty, manager operations, E.ON Ruhrgas UK E&P, told the conference. ‘It is a key area for us. We see it as being a big player in our reserves replacement and also in our expansion. We want to grow the company's production by at least 30% over the next 10 years on top of the normal reserves replacement.'

Lafferty pointed out that the SNS had the lowest offshore opex for oil and gas in the UK and was the quickest province from sanction to market. The planned divestments by ConocoPhillips and BP offered opportunities for new entrants, perhaps foreign nationals such as Gazprom. There had already been KNOC's purchase of Dana.

ERUK's planned investments in 2011/12 are £380 million net on approved projects. On the E&P side it is spudding the Tolmount exploration/appraisal well in June targeting a potential 100bcf gas field, which could involve a new platform and a tieback to existing infrastructure in the Cleeton/Ravenspurn area.
Typical fields remaining were technologically challenging, involving tight gas, low calorific value gas and high water:gas ratio. The heavily fracced Babbage development, in block 48/2a, which came onstream in August 2010, has delivered on the nail so far. There are three wells on the platform at the moment, with plans for another two wells (to be sanctioned later this year) in 2012, and potentially another two the following year. Meanwhile there are plans for production logging this May to gain a better understanding of reservoir performance.

Rita, in blocks 44/22c and 44/21b, which came onstream in April 2009, has also been technically challenging, comprising a dual lateral subsea well into the Carboniferous, tapping the separate eastern and western parts of the reservoir – a first for the SNS and for the UK, said Lafferty. ‘It has proved a resounding success, achieving pay back in 18 months – a phenomenal payback period,' he added.

In the central North Sea, E.ON Ruhrgas is a non-operating partner in a number of developments, and is operator for the Huntington FPSO oil and associated gas development, in blocks 22/14b and 22/14a, due onstream late this year. There was also exploration potential west of Shetland, said Lafferty, where ERUK had been successful in all its bids in the recent 26th offshore licensing round.

He expressed the fear that the decoupling of the gas and oil price would actually raise the cost base for the SNS. The base rate for rigs was being driven up by new developments coming through on the oil side. If the gas price stayed where it was and the oil price kept rising, then people would take their equipment somewhere else where they could obtain better rates, he argued.

Contractor comeback
Paul Thomson, chief executive of SLP Engineering, said that as a result of the Smulders investment last summer, following a period of receivership, the company won its first order in December – a 750t jacket for the second phase of the Thornton Bank wind farm offshore Belgium for delivery this June, and was now cutting steel.

Even during administration, said Thomson, the company had completed two modules for BP Valhall, the Babbage offshore hook-up for E.ON Ruhrgas, offshore modification work and hook-up on Chiswick, now operated by Centrica, and offshore modifications for ATP on Garrow. The company has over 55,000m2 of yard space and workshops in Lowestoft, with access to a highly skilled local workforce.

Thomson admitted that during the administration period the company lost many opportunities. Work on most of the 14 oil and gas projects approved by the UK's Department of Energy & Climate Change (DECC) in 2010 was awarded to foreign competition. He said he had been told by DECC that there was ‘a perception in the oil & gas community that the UK no longer has the capability to support large projects. This is a perception that needs to be changed,' pointing out that the DECC is expected to approve a further 30 oil and gas projects in total this year.

More encouraging news for the regional supply chain came courtesy of the wind energy sector.

Vattenfall director David Hodkinson told the conference his company, with partner Scottish Power, hoped to start building the first stage of the East Anglia Array wind farm off Norfolk in 2014 and produce first power in 2016. The entire 7.2GW project – hopefully to be completed by 2023 – would mean a £20 billion investment into the region, said Hodkinson, producing a legacy of skills that could transfer across the UK and elsewhere in the world in the years ahead. OE

Categories: Europe Production System Design Decommissioning

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