Edinburgh-based analysts Wood Mackenzie have identified 57 new field developments likely to come onstream in South-East Asia within the next eight years. Of these, 36 are probable developments, with the rest classified as under development.
The survey examines activity in ten countries in the region. Indonesia has the most new projects upcoming - 21 - followed by Malaysia (11), China and Thailand with seven each. (The Chinese schemes listed are all offshore.)
Most common probable development concept, representing 68% of the total, is the conventional fixed platform. Floating production and subsea developments are relatively rare, although some operators plan to use a combination of FPSOs and single fixed wellhead platforms.
Gas projects dominate the immediate future in Indonesia, Thailand, Myanmar, Brunei, and the Philippines, with only China and the Zone of Co-operation leaning more towards new oil developments. The 57 new projects overall should recover 2.6 billion bbl of liquids and 55 tcf of gas: gas represents some 78% of the total new field development base, with Myanmar's Yadana and Yetagun the two biggest new gas developments. Average size of the new field developments is 215 MM boe.
Wood Mackenzie's analysis shows that the larger fields are still being found in the established regions of Malaysia and Indonesia, although Vietnam and Myanmar have provided significant discoveries in recent years.
Between now and 2002, the analysts forecast that South-East Asian gas production from known fields will rise by over 60% between now and 2002, to cater primarily for increased gas use in Japan, South Korea and Taiwan as well as the rapidly developing (producing) nations of China, Indonesia, and Malaysia. In contrast, oil output from known fields could decline 20% by 2002.
Expenditure totalling $23.2 billion could be commiitted to the new projects over the next eight years, with the largest share going to Indonesia ($5.1 billion) followed closely by Malaysia ($5 billion). However, Natuna Gas, which is not in the probable category due to uncertainties over gas markets, could add $30 billion to the total if the development does proceed.
The Zone of Co-operation appears to be the most expensive area, rated by WoodMac at $3.85/bbl to develop due to remoteness and lack of infrastructure. Malampaya puts the Philippines second in this regard, at $2.98/bbl, due to remoteness and water depth. Myanmar and the Malaysian/Thailand Joint Development Area are rated the least costly to develop, mainly because separate pipeline companies will be responsible for developing these regions' gas pipelines.
In Brunei, the likeliest new development is BSP's Selangkir, a 300 bcf accumulation which could be tied back to the Iron Duke production facilities via a wellhead platform. Another possible is Maharaja Lela, a group of small reservoirs in the Jasra-Elf operated block B thought to contain 1 tcf, 80MM bbl of liquids. Complex geology and commercial difficulties could delay development till the next century, however.
China's probables are Lufeng, a marginal oilfield now operated by Statoil; Bohai Oil's Suizhong 36-1, a large, heavy oilfield with low recoverability; and Apache's Zhao Dong, a small oilfield which could be tapped using a converted jackup.
ARCO, Total and Mobil govern the main potential offshore developments in Indonesia. Gas/condensate discovery Peciko (5.6 tcf, 100MM bbls of liquids) is the most capital-intensive, costing an estimated $1.25 billion: Total has drilled 15 successful appraisal wells since the initial find in 1991. ARCO's Sirasun/Terang, two gas discoveries totalling 1.5 tcf west of the Kangean block, will be developed through 20 wells, mostly subsea, for $500 million.
Malaysia has five developments in the probable category. Esso's four Larut area discoveries, totalling 125MM bbl of oil, may have to wait for pipeline capacity to become available. There may be two platforms here, which would push the project costs to $500 million. Occidental's five SK8 gas/condensate discoveries could also require two platforms with up to 12 wells: development may be phased.
Cakerawala, a (mainly) gas accumulation discovered last year in the joint development area, is still undergoing appraisal. However, development is likely to be rushed through (by South-East Asian standards) for start-up by the turn of the century. WoodMac estimates 25 wells would be needed to achieve plateau production from the 2 tcf field of 350 mcf/d: platform numbers are unknown, but capex is unlikely to exceed $500 million, with PTT paying for the 1,000 mcf/d capacity pipeline (enough to tie in future discoveries in the joint region).
Thailand's key recent oil and gas discovery was made by Maersk north of the Tantawan Field in the Gulf of Thailand. Wildcat Benchamas-1 tested 44.7mcf/d and 4,835 b/d liquids. Two of the three subsequent appraisal wells were also positive. WoodMac foresees a typical Gulf of Thailand development scenario involving a central production complex with numerous satellite wellhead platforms and an FPSO for liquids export.
At one of Thailand's main established offshore production centres, Bongkot, the partners and PTT have just agreed to step up output from 350 mcf/d currently to 550 mcf/d, starting mid-1998. Gas will be sourced from the Bongkot Field and from Ton Sak, a satellite field to the north-east discovered in 1994. The project will involve upgrading the current production platform to treat up to 630 mcf/d, with two new wellhead platforms and associated sealines and a third gas processing train installed.
JVPC's Rang Dong remains Vietnam's major find of recent years, possibly holding 500MM bbl of oil and 600 bcf: the granitic basement reservoir militates against pinpoint estimates. JVPC is thought to be considering an early production system followed by a phased full field development, perhaps producing oil at 130,000 b/d at peak. Numerous fixed production and satellite platforms could be called for, offloading to an FSU in the absence of refining capability onshore Vietnam. Options for the gas are uncertain, with again no readily obvious market on the mainland.
Disappointing appraisal wells on Petronas Carigali's Ruby Field have downgraded reserves to an estimated 80MM bbl of oil and 150 bcf of gas. Again, WoodMac foresees early production using a fixed platform tied to an FPSO via a single-point mooring, in turn leading to multiple fixed platforms for the full field development. Cost of the two production stages could be close to $300 million.
Shell launches further subsea, FPSO and platform projects
Maersk Dorset arriving at A&P Wallsend for ship repair as part of its FPSO conversion for the Curlew Field.Shell has gained government approval for two new UK sector projects, with a third also pending. At the Gannet complex, 112 miles east of Dundee, two new satellite fields are to be linked to the central production platform, stationed in 95 metres of water. This has been producing oil and gas through three existing satellites since 1992.
Under the new £90 million extension, the Gannet E and F Fields will be brought onstream next year by single production wells tied back by a common subsea pipeline system to the Gannet Alpha platform. Rockwater has the £29 million EPIC contract for the flowline bundles, which should be installed next May using the controlled depth tow method. Drilling of the wells will be handled this winter by Sedco 7O4.
Of the two new wells, E will be the more challenging. The tieback distance is long, at 14 km, and the 23MM bbl reserves are heavy, thick crude (20!API). A Lasalle electrical submersible pump will be installed, possibly the first in a North Sea subsea production well.
E's crude will also necessitate a pipeline system with a high level of insulation to ensure the crude remains hot on arrival at the platform. This will be achieved through a dry, insulated cavity in Rockwater's three bundles. These will be towed to the seabed for placement between the platform and the wells. Gannet A and E bundles will each house two insulated eight-in. production flowlines and a single three-in. gas lift line. Gannet F's will contain one eight-in. production flowline and a three-in. gas lift line.
Gannet E production should peak at around 8,000 b/d with a field life close to nine years. Gannet F, also a 14 km tieback, has 19MM bbl of lighter crude which should last 16 years, peaking at 12,000 b/d. ABB Vetco Gray is supplying the subsea trees and Kvaerner FSSL the subsea controls.
Shell also announced confirmation of its Curlew development in block 29/7, 220 km east of Aberdeen. The 71MM bbl of oil/condensate and 244 bcf of gas are to be developed by converting the tanker Maersk Dorset to an FPSO for initial production next autumn. The revamped vessel will have oil storage capacity of 560,000 bbl which will be offloaded to a shuttle tanker. The gas will head to St Fergus via the Fulmar pipeline.
This is yet another fast-track FPSO development: the second Curlew accumulation was only discovered in 1994. Maersk UK is leasing the vessel, which will be delivered on an EPIC basis by the MAS Alliance of Amec, SBM and Maersk Contractors. Initially, A&P Tyne will perform conversion of the 100,000 dwt tanker, with SBM supplying the mooring turret. Then it will be towed to Amec on Tyneside for topsides installation.
Coflexip Stena Offshore will install the gas export line and Borgland will drill the wells: Curlew's production life is currently estimated at eight to ten years. This project, priced at £300 million, will produce Shell's second North Sea FPSO close behind the recently completed Anasuria for Teal, Teal South, and Guillemot A.
Finally on the Shell front, Trafalgar John Brown won provisional agreement last month to engineer, procure, build and install the Galleon Phase II PG satellite wellhead platform in southern sector block 48/14. This will be a normally unmanned installation comprising a 760-ton jacket and 970-ton topsides with three decks. TJB's Methil yard should begin fabrication in November, assuming DTI approval is clinched this month, leading to installation of the platform at the end of next year.
Other activity
Another outstanding project in the UK Central North Sea is finally coming together. Elf has just confirmed award of the Elgin and Franklin wellhead jackets to Saipem UK as main contractor. Tecnomare is performing engineering and design work, with Lewis Offshore building the jackets, which will weigh around 2,500 tons. Installation should follow in the second half of 1997.
A full field development may have been submitted to the DTI this month with a view to a possible production start in 2000. Bids for the main piece of hardware, Elgin's central production platform, are currently being narrowed down. Shell may also announce this month the winner of the wellhead platform for Shearwater, expected to share a gas export line with Elgin/Franklin.
Few other large fixed UKCS structures are in prospect for Britain's fabrication yards. The Offshore Contractors' Association predicts a slide in fixed structure work at the yards from 9 million manhours this year to 3 million manhours in 2000, although this does not take into account new field developments that may suddenly arise. Some major gas projects may be resurrected, OCA adds, which might generate calls for smaller platforms.
Other types of work should increase, with floating production systems accounting for over a third of the UK yards' total workload by 2000. Export work, currently 20% of their activity, should also increase slightly, and there may also be opportunities in the form of decommissioned platforms.
Another report on the UK sector, by Wood Mackenzie, suggests the number of new fields coming forward for development is declining. It has identified 50 probable prospects between this year and 2003, compared with 67 listed last year, yielding 1.8 billion bbl of liquids and 7.7 tcf in total.
Capital expenditure on these probable fields is estimated at £7.2 billion, down 30% on WoodMac's forecast of £10.5 billion for last year's 67 probables. However, the analysts add as a caveat that there are 160 tight holes currently on the UKCS, including some significant ones on the Atlantic Margin, which could rearrange the picture once results are revealed.
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