Further redevelopments in prospect on abandoned fields
Jeremy Beckman
Editor, Europe
Throughout the UK North Sea, options abound for production turnaround programs. Experience has proven that neglected fields, underused platforms, and underperforming wells can all be revived under new management.
Owners of these assets are still open to outright sales. For most newcomers to the shelf, the problem is securing funding in these straitened times, but this is not an issue for Fairfield Energy. Since its formation in late-2005, the London-based company has come from nowhere to operate Dunlin A, one of the North Sea’s longest-serving production platforms.
Fairfield has ambitious plans to extend the facility’s lifespan beyond 2020 through a series of overhaul measures and satellite tie-ins. Elsewhere the company is looking to monetize various under-developed fields, partly through application of innovative drilling techniques.
The management team is led by chairman Chris Wright, formerly Unocal’s senior VP for Global Exploration and Technology; and CEO Mark McAllister, who worked with Wright in the 1990s at leading UK independent LASMO.
The company started out with a line of equity totaling $200 million supplied by management and a syndicate of private equity investors, led by Warburg Pincus. The fund has since doubled to $400 million, and Fairfield continues to raise finance for its various projects. "Having good funding in place is essential, given the capital-intensive nature of the North Sea," McAllister says.
Staff numbers have risen to 50, divided between the Staines head office, west of London, and the operation in Aberdeen, which is dedicated mainly to the Dunlin area fields. The Aberdeen branch is supplemented by personnel from Seawell, which has been reconditioning the Dunlin A platform rig, and from the platform duty-holder Amec.
Fairfield started out with core skills biased towards geoscience and reservoir engineering. "Our in-house understanding of complex reservoirs is our strength," McAllister claims. "We operate our own workstations, and outsource as little subsurface work as possible. Our team brings a wealth of North Sea experience along with relevant knowledge from projects in regions such as the FSU, North Africa, and Latin America."
Planning ahead
Fairfield acquired its interests in the Dunlin area from Shell, ExxonMobil, OMV and Statoil early in 2008, but the initial approach came in late 2005. "When we first had a conversation with them, Fairfield had only been in existence for a month," McAllister explains.
"It took Shell and partners a while to get comfortable selling a field of that maturity to a company our size. In order to make the transaction, given where we had come from, we had to work extra hard to demonstrate our technical skills and commercial creativity. We also provided great detail of our financial status, putting all four companies in touch with our investors."
Shell and ExxonMobil had put numerous other northern area fields and platforms up for sale. "We chose the Dunlin assets for their reserves upside. When we looked at the assets, we saw tremendous growth potential. We never cite cost reduction in our acquisition case. This will always be a longer-term challenge, because we don’t have the economies of scale that the Majors have, for instance in logistics.
"From the UK government’s point of view, the licensing body DECC wanted to bring new players into the UK North Sea, particularly via the Promote License system. But very few of these companies have all-round technical capability for mature field operations, especially where decommissioning is an issue.
"However, we had a very clear understanding of how we intended to operate the platform, and we carried DECC with us every step of the way. Before we started our negotiations with Shell and partners, they wanted clear assurances that DECC would be comfortable with our plan."
Under the transaction, Fairfield acquired 70% of the equity in and operatorship of the Dunlin cluster in Quadrant 211, comprising the Dunlin and Dunlin South West fields, and the subsea tiebacks Osprey and Merlin. The remainder was purchased by MCX, part of Mitsubishi Corp.
The Dunlin cluster of fields are in a water depth of 151 m (495 ft), around 195 km (121 mi) northeast of the main Shetland island. At the time of the transaction, combined production was down to 5,000 b/d.
Dunlin was discovered in 1973, and brought onstream in 1978 via a single concrete gravity structure platform with oil storage in its base. Early in the field’s life, recoverable reserves were estimated at around 365 MMbbl of oil and 5 MMbbl of natural gas liquids. Production, from mid-Jurassic Brent sands, peaked at 116,000 b/d in 1979. The field was also the first to produce through the Brent pipeline system to Sullom Voe, Shetland, via a 24-in. (61-cm) pipeline link to Shell’s Cormorant A platform.
A separate prospect was discovered northwest of Dunlin, named Osprey. This was brought onstream in 1991 via two eight-slot subsea manifolds, one for production and the other for water injection. Osprey’s oil is exported to Dunlin A 4 mi (6.4 km) to the southeast through two pipeline bundles. Water injection was needed from the outset to maintain reservoir pressure, peaking at 70,000 b/d.
Project management group Amec was appointed Duty Holder of the production facilities, leaving Fairfield to focus on field development, drilling, and well maintenance. "This outsourcing arrangement is now fairly well defined in the North Sea," says McAllister. "Amec was not a Duty Holder at the time, but was very keen to become one, although many of its staff already worked on the platform under Shell’s Sigma 3 North Sea asset maintenance program.
"We are delighted with the outcome, which so far has worked well. As for retaining Shell’s team on Dunlin A, we had to explain the issues of transferring from an oil company operator to a contractor. We convinced them we could commit greater investment to the assets so that they wouldn’t wither on the vine. They appreciated that."
Fairfield engaged Aker Solutions in Aberdeen for a three-year program of engineering and construction services, including modifications to the platform. Bibby Offshore was contracted for engineering and diving support for an IRM campaign on Dunlin and Osprey, using its newbuild DSVBibby Topaz. And consultants Genesis Oil & Gas were awarded a five-year contract for conceptual and subsea engineering studies, initially for Dunlin, but with an optional extension to Fairfield’s other projects.
For subsea well development and workovers, Fairfield secured Transocean’sSedco704 for six months, under a program supervised and designed by ADTI. Fairfield, however, is managing design in-house of wells drilled from the platform’s rig, newly upgraded by Seawell.
Injection, power overhaul
When Fairfield and Amec took the helm, they encountered no major surprises among the facilities. "We had done very significant due diligence with Amec, who were already present on the platform. And we had talked to Talisman Energy, Apache Oil & Gas, and Venture Production about their experiences with the majors in taking on North Sea assets.
"Something we hadn’t picked up on was the wall thickness of the 20-in. (51-cm) casing for the platform’s water injection wells. We found that when we injected a compressive load, the casing didn’t have a sufficient safety factor. We started addressing this in May 2008 by putting collars in the wells to share the load between the 20-in. and 30-in. (76-cm) casing, and we were able to resume injection last September.
"Our foremost priority remains water injection. When we took over, the average injection was down to 50,000 b/d, but over the last three months, we have been averaging 180,000 b/d. At the moment, we are progressively overhauling the platform’s injection and sea water lift pumps, and – most important – power.
"Dunlin relies on power imported from the Brent complex via a subsea cable. We put five Aggreko generators on the platform to provide temporary back-up, and we have also changed the engine on one of the existing Avon generators. We will then refurbish that engine and transfer it to a second Avon generator. Our long-term plan is to lay a new 12-in. (30.5-cm) pipeline connecting to the Northern Gas Leg Pipeline system to bring in new supplies of gas. This will be ready by 2012, with limited topsides modifications on Dunlin."
Prior to taking over, Dunlin’s platform rig had not been operational for five years. "In the next few weeks," says McAllister, "it will re-start, drilling sidetracks and new injection wells, and then workovers, water shut-ins and re-perforations. We will also convert some of the wells to run electric submersible pumps for the first time, a program which Schlumberger is managing.
"There are 48 well slots available on the platform, but currently only eight active producers. The amount we end up using over time will depend on the conclusions of our subsurface team in Aberdeen, which is currently working flat out to identify new drilling opportunities."
In May, Fairfield and Mitusbishi completed another transaction with Shell and ExxonMobil, acquiring offshore acreage adjacent to Dunlin which includes the undeveloped Skye and Block 6 discoveries. Last November, Fairfield also picked up an exploration block immediately east of the Dunlin field.
"We plan to drill the known structures and any identified prospects from the platform, thereby lowering our costs. We are proving up the viability of this low-risk, satellite strategy from the results of our infill drilling to date."
Since January 2008, Fairfield’s program has doubled production to presently 10,000 boe/d. The long-term plan is to extend output from Dunlin alone through 2018-2020. Adding in the various tiebacks, the potential is much greater.
One of the earliest satellite programs is currently stalled. Antrim Resources submitted a development plan for its 15.6 MMboe Causeway field last December. Causeway was discovered in 2006, and subsequent appraisal drilling means there are six suspended wells currently available for a development.
Following an agreement signed last September, Fairfield performed a FEED study on modifications to Dunlin A, the nearest host platform, with assistance from Senergy on development planning and CSL on subsea engineering for a 9-km (5.6-mi) tieback. However, Antrim decided to push back the schedule in the hope of lowering its capex costs, and Causeway may now not come on stream before 2011.
Crawford reservoir cross-section.
Last October, Fairfield contracted Cyclotech for hydrocyclone clean-up technology for the platform. Up to that point, Fairfield had made progress in reducing produced-water oil content, but the new investment is intended to achieve a further reduction. "Cyclotech has done work on changing out the liners on one of the existing hydrocyclones," explains McAllister. "We’re evaluating the benefit of those changes, but we also want to do more to increase our produced water-handling capabilities, including a possible switch to produced water re-injection."
Crawford revival
Crawford in the central North Sea was first developed by Hamilton Brothers in 1989, but was decommissioned shortly afterwards due to production issues. The current partners are Fairfield as operator, with 52%; Stratic Energy, 19%; and Valiant Petroleum, 29%.
In November 2007, Fairfield drilled an appraisal well that confirmed a northerly extension of the Triassic Cormorant formation reservoir. The well also encountered a 62-ft (18.9-m) oil column in a separate Tertiary target, named Delta A. At the time, Fairfield planned a hydraulic fracture to test the well, but problems arose while cementing the 7-in. (17.8-cm) liner.
Marathon has agreed in principle to host a subsea development from its Brae East platform 30 km (18.6 mi) to the south. Preparatory work is under way to modify the topsides, which will probably also handle production from BP’s Devenick development. "Marathon’s behavior has been exemplary in extending the life of its assets through third-party fields," says McAllister.
"All our studies are complete – we know our development scenario." The project will involve horizontal wells with multi-fracing, a technique that was not available at the time of the previous development." Recently, Fairfield became operator of adjacent block 9/27a, which may provide scope to tie in further accumulations.
To the south in block 16/29a, Fairfield worked for a time with Apache on re-development of the Maureen oil field, abandoned by Phillips in 1999. According to McAllister, Apache was looking to repeat its success in reviving production from the Forties, but a three-pronged side-track well on Maureen, based on seismic anomalies, was not successful.
Last year, Apache pulled out, leaving Fairfield as the sole licensee. The company is looking for a partner to co-fund an appraisal well which would also serve for a development – subsea wells tied back to a nearby platform, possibly BP’s Andrew or Talisman’s Varg FPSO in the Norwegian sector. "We still see this as an attractive development," says McAllister. The scheme could be extended to take in other fields in the area produced previously by Phillips.
Fairfield has further plans to revive Staffa, another prematurely decommissioned oil field which it picked up last year under the 25th licensing round. The field is in the northern North Sea, close to the Ninian complex.
The company is also building a position in the southern UK gas basin. In April 2008 it acquired the undeveloped Clipper South field from Shell and Exxon Mobil, and this year RWE Dea farmed in as 50% partner and operator. Independently audited recoverable reserves are estimated at more than 200 bcf.
Clipper South is in the Sole Pit basin within the Rotliegend tight-gas play fairway. The location is northeast of the Anglia field, where RWE Dea is again a partner. The development will be based around an unmanned platform with six horizontal multi-fractured wells.
Multi-fracing is a technique which RWE Dea has applied successfully in the Mittelplatte field off northern Germany, and which has also worked well on other tight gas structures in nearby the southern sector, such as Chiswick and Ensign. "The whole Rotliegend tight gas region will be a major play going forward," McAllister predicts.
