EIGHTEEN months have swept by since Fairfield Energy took over operatorship of the North Sea Dunlin field from Shell, since when a great deal has been done to rejuvenate the asset. And Fairfield has aggressively grown its portfolio, taking advantage of the fact that Dunlin is, in effect, paying the bills.
A combination of solid cash flow and the fact that Fairfield is privately financed has enabled the company to sidle past the worst effects of recession and the most recent oil-price gyration and get on with growing.
However, Dunlin has not been a walkover. CEO Mark McAllister, his team and his supply chain, essentially led by Amec, have had to work imaginatively to build production.
McAllister told Energy that Dunlin presents a suite of challenges, paramount among which is sustaining asset integrity for the long-term – at least 10 years.
Another is ensuring effective water injection, which is fundamental to sustaining output from such a mature asset that eats power.
“We’ve changed out one of our Avon generators and will change the other one out in 2010,” said McAllister.
“We’ve seen an increase water injection on Dunlin, which probably averaged around 35,000bpd for several years. Our best month in 2009 has been 150,000bpd of water per day, on average, in return for production improvements.
“When we took over Dunlin, it was doing about 5,000 barrels per day of oil.
“Today, it’s 12,000bpd, so we’ve seen a significant improvement.”
But has this matched expectations, bearing in mind that it’s one thing checking out a platform before purchase, but perhaps quite a different experience once purchased?
“Well, we did a lot more than just tyre kicking.
“That’s a very important part of this answer because we’re very well experienced North Sea operators in different guises in different companies.
“Our friends at Amec were very familiar with this particular asset. We have watched the experiences of Apache, Venture and others as they took on mature assets, so we came into this very much with our eyes open.
“Even so, I think the biggest challenge has been not so much the state of the asset and what we’ve needed to invest, but the daily balancing act of bed space and priorities for helicopters and boats as we’ve tried to do things to increase water production, improve asset integrity and, at the same time, upgrading the platform rig so we can drill from January.
“So no huge surprises from our due-diligence process, just that the daily challenge of planning activity is quite significant in itself.”
McAllister said he has five or six wells mapped in for 2010.
Three of them will be fitted with ESPs (electric submersible pumps) to parts of the field where there are fault blocks not in communication with the main part of the field, which is at a lower reservoir pressure.
There are also a couple of infill wells within the field planned, plus there is a target in a fault block just outwith the core area of Dunlin.
“We see ourselves drilling through 2010 then having a break from that activity for most of 2011 while we do all the topsides work involved with bringing in our own imported fuel gas from NLGP.
“We’ll probably start drilling again early-2012 and are working through a hopper of opportunities at the moment.”
So will there be a material increase in production as a result of the 2010 drilling programme?
“Yes. We’re aiming towards 20,000bpd … that’s where we would hope to get the Dunlin area to. Dunlin is the cash generator.”
Other than Dunlin, Fairfield has a list of priority projects, numbered among which is bringing the North-west Hutton (NWH) area of the North Sea back to life.
However, this is not to be confused with cranking up the original field operated by BP, which is at an advanced stage with decommissioning of the NWH platform and associated infrastructure.
NWH came on to Fairfield’s radar about four years ago, but it took a considerable time to conclude negotiations because of the need to decommission existing infrastructure.
“Our ideas for NWH don’t involve much that lies within the drilling-radius footprint of the old platform,” said McAllister.
“There’s quite a lot of proven oil in the southern part that was never really developed.
“What we’re calling Darwin, which will be the redevelopment project, will be a combination of what we’re buying from BP and its partners in NWH, plus the 25th Round block immediately to the south that we’ve picked up.”
At the heart of what BP offered the marketplace via Indigopool was a development opportunity, apparently with potential reserves of more than 80million barrels of oil.
McAllister: “It’s a fresh development … subsea. Whether it will be a full subsea development tied back to Dunlin or subsea with an FPSO and gas export to Dunlin, or stabilised crude export to Dunlin, we’re still working through the development concepts.
“We see a significant reserves opportunity there. I won’t say more than that. Development onstream 2013-14 or thereabouts.
“That’s not the only opportunity that comes with Dunlin ownership because, before we ever develop Darwin, we have the Skye block 6 discoveries from Shell which we see coming onstream in 2011 as subsea tiebacks.
“So we have concentric circles of water injection, platform drilling, appraisal drilling from the platform, tying back Skye on block 6 and then the big step-out … tying back Darwin.
“It adds up to a multi-year plan to make the very most of this piece of infrastructure.”
Down in the Southern Gas Basin, the big focus for Fairfield is the relatively fresh Clipper South discovery located originally by Shell.
“We did a deal with RWE-DEA. They’re in as operator, talking about a gas development in a geology where you’re going to apply an approach that has been very successful in the US – multi-fraccing (multiple fracturing of reservoir rock).
“Clipper South is a large accumulation with about 400billion cu ft in place. The challenge is how much we manage to get out through multi-fraccing.
“Our P50 recovery factor for this is around 50%. Anything above this is a real upside, bearing in mind that traditional gas developments are capable of yielding 90-95% of in-place reserves.
“We approached RWE and invited them to join us in this because of a lot of horizontal multi-fraccing experience that they have onshore/near-shore Germany.
“With their acquisition of Breagh, they’re building quite a substantial development team, and we see significant economies of scale growing out of that.
“We’re in negotiation with two or three potential host facilities.
“We see Clipper South as two phases of three wells each,” said McAllister, adding that he was comfortable with the project’s threshold pricing of gas, the value of which fell sharply through 2009.
Not everything goes as planned and, for Fairfield, the big disappointment appears to be Maureen, which was abandoned by ConocoPhillips in 1999.
“We had hoped when we picked up Maureen that we would find significant untapped resources in that field. We invited Apache to join us on that, obviously key off their success on Forties. We drilled a well in 2006 with Apache as operator. Indeed, we drilled a couple of locations, both of which were disappointing in terms of proving up the basic thesis.
“We then took on the licence 100%, thinking there was one more location to be drilled to really prove or disprove our theory about the Maureen field itself. The target was a part of the main Maureen field, but beyond the reach of the original wells.
“We felt there was a measure of risk, so we farmed down to Endeavour and Challenger. That well was drilled early-2009. It certainly didn’t prove up hydrocarbons that we would view as commercial at this stage. There are other horizons … not just the Palaeocene … deeper ones, but Maureen is not top of our agenda. It’s on the back burner.”
Disappointing, too, has been progress on Crawford, which was an early acquisition by Fairfield.
This is a sizeable field – 200million barrels of oil “undisputed”, according to McAllister.
A development scheme for Crawford had been drawn up based on horizontal multi-fraccing. The alternative was multi-laterals. At the time, the planning work was carried out, rig rates meant that multi-fraccing appeared to be the better option.
“But we’ve gone back to multi-laterals … looking at slimmer hole drilling and taking advantage of falling rig rates,” said McAllister.
“It’s definitely something that’s high on our agenda and one can expect to see some movement over the next few months.”
McAllister is optimistic that a decision on developing Crawford will occur sooner rather than later, with filing the field development plan this year a distinct possibility.
The Fairfield team like challenges – witness Staffa, a field that McAllister described as “the North Sea’s largest candle”.
This is a field that was developed by Lasmo in the mid-1990s, but twice the pipeline blocked up for a combination of reasons.
“It’s a relatively high GOR (gas:oil ratio) crude for the Brent system, so you get a lot of gas coming out of solution, and when the pressure drops, you get hydrates forming – and if it’s cool enough, wax starts to precipitate.
“We’ve gone back to basics with Staffa. We’ve got a lot of crude from the original development … not small samples, but barrels of the stuff.
“So we’ve done a lot of work on production chemistry and have a range of solutions, from insulated pipelines through to chemical treatment. We believe this thing could be redeveloped quite successfully.
“We’ve completely rebuilt our reservoir model … fully simulated … it’s on a much smaller scale than Crawford, but it’s a very interesting potential development and something that we’re pushing forward to try to get to project sanction in the near term.”
McAllister sees Staffa as a very easy tieback, most likely a single well, with ample hosts to choose from.
“There are lots of facilities that are very keen on getting fuel gas, and this thing has a lot of gas. It’s a relatively straightforward development. We’re not talking about anything more than a 10million barrels size of development.
“From a reservoir perspective, it originally performed very well. Among our various opportunities, this one really is more of a production chemistry challenge rather than a reservoir engineering challenge.”
So which solution is the most promising?
“I think it’s a mix of insulation and chemical treatment.”
The foregoing makes for a pretty full activity book for Fairfield, but are the company’s finances up to the challenge, and did the credit crunch have much of an impact, bearing in mind that Fairfield is not listed?
“We financed ourselves differently for a very good reason,” said McAllister, adding that he was glad not to be exposed to the AIM market.
“We knew that before we started. We’d been around the block a few times.
“I think the other thing is that it’s not just been the nature and the size of the private-equity funding that we’ve received, but also the quality and intelligence of the investors, their understanding of the E&P business, their understanding of its risks and rewards and being on the sector’s wavelength.
“They’ve been very considered in everything they’ve done. You might find some investors who just want to take a punt on the oil price, but these guys are focused on our technical ability and on delivering value.
“When we completed on Dunlin, along with our investors, we decided to hedge the base production as oil prices were looking very strong. So our base production all the way through 2010 for the original amount that we picked up from Shell is $115 per barrel. That’s a great place to stand.
“That doesn’t come out of good fortune. It comes out of having a group of investors who are very thoughtful about what they do.
“When we formed the company, we knew the North Sea was a big table-stakes game and we felt that we needed a substantial amount of private equity to get ourselves to the degree of maturity needed to establish ourselves as a company.
“We’re only partway through our line of equity from our investors. There’s still considerably more to come from what has been committed to us.
“We obviously funded Dunlin through a combination of their equity plus a debt facility that we put in place with our partner, Mitsubishi. Outside of Dunlin, we are debt-free as a company.”
Commenting generally on financing the North Sea, McAllister says debt markets are nowhere near back to where they need to be for this province.
He thinks the pendulum went from madness to over-conservatism and has not really swung back to the middle in terms of project debt finance.
“However, the equity markets are buoyant and the North Sea equity market is crying out for an independent UK operator (of merit).”
McAllister said Fairfield was not afraid to seek further funding to get to the next stage of development, and would probably be back at the money well before 2010 is out.
Does that mean he is also on the acquisition trail?
“Always. You might ask, are we breathing?”