Burlington Resources has energized the lethargic UK sector with a series of new field developments in the Irish Sea. Plans include the sector's first application of subsea and multilateral development wells. Irish Sea production currently comes from two major complexes - the multi-field, BHP-operated Liverpool Bay, and to the north, the Hydrocarbon Resources (HRL)-operated Morecambe fields.
Morecambe's gas reservoirs, discovered 25 years ago, remain among the UK's largest. Over the past two decades, exploration drilling close to Morecambe revealed further sweet and sour gas accumulations. However, several factors mitigated against development:
- Morecambe fields' productivity and longevity, which amply served existing gas sales contracts
- Cost of installing new facilities to strip out hydrogen sulfide from some of the discoveries
- De-merger of British Gas' (BG) trading divisions in 1997. This put Centrica in charge of the Morecambe fields, through its subsidiary HRL, while BG E&P was left with the satellite discoveries. BG's portfolio was already top-heavy with gas, which it was struggling to develop in a newly liberalized UK market.
A sell-off was inevitable, and Burlington came in with the right offer in October 1997. The Houston-based company had just undergone a merger with LL&E, but production remained too focused on US onshore and offshore operations. When the Irish Sea properties became available, "we felt we could transfer the same low cost approaches that we had cultivated in the Gulf of Mexico," explained Burlington Resources (UK) Director and General Manager Earl Reynolds. To manage planning for this and other operations in Algeria, Reynolds established an office for Burlington in London early in January, also recruiting professionals who had studied Irish Sea satellites.
For $157 million, Burlington gained all of BG's East Irish Sea interests, including outright control of 10 blocks containing the sweet gas Millom and Dalton discoveries, plus the five-field sour gas Rivers group. It also gained interests in four non-operated blocks nearby.
The discoveries are roughly 45 km offshore northwest England in water depths over 100 ft. Conveniently, the acreage had been well
covered by 3D seismic. By applying its own detailed reservoir characterization techniques to the data, Burlington also identified further targets for future exploration drilling.
The immediate development priorities were Dalton and Millom. Dalton, in block 110/2b, was discovered in 1990 through a well
that tested gas from the Carboniferous at 90 MMcf/d. That well was then suspended as a producer, with estimated reserves in the field of around 120 bcf.
According to analysts Wood Mackenzie, the first Millom discovery well, on block 113/26a, encountered a poor quality, gas-bearing Triassic Sherwood sandstone reservoir that tested at 14.6 MMcf/d. Eleven years later, BG drilled an appraisal well on block 113/27a (Millom extends over two blocks) which led to an initial in-place assessment of 695 bcf. Recoverability, however, looked to be constrained by the presence of platy illite, which would impact permeability. In 1996, BG drilled a further appraisal well (horizontal), also suspended as a future producer. Extractable reserves are now thought to be around 400 bcf, but production experience will be needed before that figure can be verified.
Burlington took the view that recent advances in drilling technology could make these fields workable. From its US operations, it also brought good knowledge of tight gas reservoirs.
The plan for Dalton was assembled in 1998, ready for UK government sanction in October. The scheme involves two subsea wells tied back 10 km northeast to the Morecambe North platform via a PLEM and 12-in. flowlines. Gas will be commingled at the platform with Morecambe North supplies, then sent north through an existing 32-km, 36-in. pipeline to Centrica's Westfield Point processing terminal in Barrow. This April, Burlington also secured government approval for Millom East, a single well subsea tieback from the eastern part of the Millom Field to the Morecambe North platform.
The jackup Ensco 72 has drilled and completed the three development wells (two being re-entries/workovers). Dril-Quip has supplied the subsea trees, Duco the control umbilical, and Kvaerner Oilfield Products the subsea control system. Stolt Comex Seaway is managing subsea installations. By July, Dalton's flowline and umbilical were in place, and the risers were hydrotested. To help local fishermen, the subsea structures were designed to be overtrawlable.
The Sea Nova concept has been deployed only once elsewhere for gsa production purposes - on Unocal's Q1 platform in the Dutch sector:
According to Hook-up and Commissioning Coordinator Steve Livingstone (on secondment from HRL), the contractor has had to adapt to the tidal flows in this area. The seabed happens to be soft and sandy, clouding the water and thereby creating poor visibility for the divers. This also may hamper maintenance during the production phase.
On the plus side, commissioning and installation of subsea equipment was completed within the allotted six-week window, and first gas from Dalton may now flow earlier than the projected date in October. Millom East should also be onstream before year-end, at around 10 MMcf/d.
Burlington figured that Millom also warranted a dedicated platform on the western section. It opted for a Sea Nova minimum facilities installation, designed by Ocean Resources of Monmouth, UK. This design had been deployed previously, for Unocal's QI Halfweg Field in the Dutch North Sea, and also for defense purposes in UK waters.
Sea Nova is self-installing. It can be floated over on a barge without the need for specialist heavy lift vessels. Its conventional trussed deck (20 meters by 6 meters) is supported by four unbraced tubular column legs fixed to a cellular reinforced concrete gravity base. It can also be fitted with a moonpool and conductor slots for pre/post-drilling operations.
Risers and J-tubes are conducted to the seabed inside the column legs.
According to Reynolds, the concrete base is easy to fabricate and environmentally friendly, once in place. Above all, from Burlington's viewpoint, the platform should be easy to de-ballast when the time comes for decommissioning. Ocean Resources also claims that capital outlay for this design is only 40-60% of a conventional platform.
Burlington was aiming for UK government clearance for the Millom West scheme in July, allowing it to have the platform ready for installation in the first quarter of 2000. Under an EPIC alliance contract, Consafe and Ocean Resource will handle design, fabrication and assembly of the gravity base structure (GBS), steel support structure, deck and process equipment. Genesis is responsible for topsides engineering, and Stolt Comex Seaway for the installation and pipeline tie-ins.
This platform will also be tied back to Morecambe North through a 12-in. spur line. Further development drilling should boost production to 80 MMcf/d in 2001, with output declining slowly from 2002 to the anticipated field end in 2017. Two of the planned wells could be multilaterals. Burlington may drill an additional exploration well in the area. Alliance Resources, with 10%, is Burlington's only partner in the Millom field developments. Wood Mackenzie estimates that both phases of the development could eventually cost £111 million.
HRL will operate the platform and subsea installations on Burlington's behalf from the DPPA production platform on Morecambe North, which has been in service since 1992. North Morecambe still produces at a plateau level of 588 MMcf/d, although that figure will decline from 2001. Of that total, 7% is nitrogen, which has to be blended, and 6% carbon dioxide, which is stripped out at Barrow.
Brown & Root AOC - HRL's engineering and operations support coordinator - is managing modifications to the Morecambe North platform to handle the new supplies. One key change is the need to accommodate production year-around from the Burlington fields. Output from the Morecambe fields is shut-in during the summer months, as demand from the mainland declines, but Burlington has a separate sales contract.
The new developments have also necessitated a design review of the Barrow facilities. "We've had to verify that the terminal can process new gas in isolation from Morecambe North," says HRL Production Manager George Spicer. Trials are in progress at the terminal of a simulation package for this purpose.
Among the modifications to the Morecambe North platform are the addition of hydraulic power units to control the Dalton and Millom East subsea valves, plus an extra methanol package for the umbilicals. The distributed control system had to be upgraded (a Y2K-compliant system from Fisher Rosemount was selected) and additional logic had to be imported into the emergency shutdown system.
The DPPA platform on Morecambe North will be used to control operations on the Millom and Dalton fields
New ultrasonic meters are being installed to monitor input from the third party fields. According to Steve Livingston, "these will take into account the fields' share of exported gas, nitrogen levels, and so on. All the kit has undergone thorough factory acceptance tests." Real Time Engineering in Glasgow, UK is providing the software. A Hazop study is also being executed for the Sea Nova platform.
Having demonstrated that subsea tie-ins can be achieved swiftly in this sector, HRL hopes that other operators with discoveries nearby will consider similar tiebacks, under HRL's guidance. The platform was originally designed to handle production from satellites.
Assuming the Sea Nova concept works on Millom West, a lookalike could be applied to Calder in block 110/7a. This is one of the five Rivers prospects - the others are Asland, Crossans, Darwen, and Hodder - which may have combined reserves of 300 bcf. The sour gas from these fields cannot be commingled with Morecambe's, so a separate gas export system will have to be installed. Options under consideration at present are:
- New pipeline from the fields south to the Douglas platform in Liverpool Bay, which already processes sour gas for onward transport to the Point of Ayr terminal in North Wales
- Longer line that would head directly to Point of Ayr, from where supplies are sent to a gas-fired power station
- Alternatively, the pipeline could be directed north to Barrow, where a new hydrogen sulfide stripping facility would have to be built. HRL has 150 acres of land available alongside its existing terminal that could be used for processing third party gas, subject to planning permission.
Compression, workovers maintain high output at UK's largest field
Morecambe South, discovered by British Gas in Irish Sea blocks 110/2, 110/3, and 110/8 in 1974, was brought onstream in 1985, and still has a further 2.5 tcf of recoverable gas. The 32 sq mile, highly faulted anticlinal, north-south trending structure still produces at a plateau level of 1,800 MMcf/d (equivalent to 15% of the UK's peak demand). However, some modifications have been necessary of late to maintain that level.
The field is exploited through seven platforms - one central unit for processing and one accom modation unit, plus five more for drilling and production. Without slant drilling - the first application offshore in Europe at the time - eight more platforms would have been needed. Gas is piped to the Centrica-owned terminal in Barrow.
Compression was added in 1992, but was never fully compatible with the original control system from Ferranti. However, as part of a £60 million investment on the field, the supervisory control system is being replaced this summer by a new automated system from Bailey. The new system will improve status visibility of the remotely controlled platforms at Barrow, as well as rationalizing the control center network on the various offshore installations. Work was performed during the field's annual shutdown.
To improve well deliverability, a workover program was also initiated on the DP8 and 6 satellite platforms, which led last year to 10 wells being re-perforated followed by a further 10 this summer. A new well was also drilled from the DP4 platform in 1998, while in the northern part of the reservoir, an exploration/appraisal well was drilled to prove up further reserves. Both wells were managed by Global Marine. Design of the wells and completions mirrored those of the original development.
The reservoir now produces at 66 bar closed-in wellhead pressure, compared with 125 bar when production started. Recently, compression was enhanced offshore through the upgrading of two RB 211 engines to generate extra horsepower. Fine-tuning was performed using MSE's Gasman software. Added compression will also be installed at some point in Barrow.
Despite these measures, production from the field will start to slow annually by 3 MMcf/d. However, following its experiences with Burlington, operator HRL may offer some of the well slots spare on each drilling platform for other third party discoveries in the Irish Sea. The plant is also available on the central CPP1 platform and at Barrow to handle extra gas processing. HRL is also considering sharing a rig with Burlington for further exploration of its own, serviced from HRL's own Irish Sea support base in Heysham.