Timor Gap team advances Elang, but gas remains the key objective

Locations of the wells drilled so far on the Bayu-Undan field. [56114601.gif - 72k]

First oil from the Timor Gap Zone of Cooperation (ZOC) finally looks set to flow from mid-1998. But it will likely be remembered as a curtain-raiser to a much grander-scale gas/liquids production project.

The BHP-operated Elang and Kakatua oilfields in ZOC A Permit 91-12 will reportedly undergo development next year, assuming that the Indonesia/Australia Joint Authority grants approval. Under a scheme thought to cost $70 million, the two fields will be developed via an FPSO vessel and subsea completions.

Field life may only be three years, due to the modest size of the oil reserves (17MM bbl). These have been heavily downgraded: at one point during the elation over the initial Elang-1 discovery early in 1994, that prospect alone was rated at 100MM bbl.

That September, a 1.7km step-out to the west, Elang-2, confirmed the promise by flowing 6,080b/d and 7,500b/d of 55deg API crude from two separate Montara sand intervals. However, realism set in following the gloomy results of 3D seismic and three further wells in the vicinity of Elang in 1995. Of these, only Kakatua-1 proved worthwhile, testing similar quality crude to Elang-1 at a maximum stabilized rate of 9,000b/d, again from Montara sands.

Post-Kakatua, a fast-track development was proposed which might have got under way a year ago, based on the conversion of BHP's Skua Field FPSO. However, BHP's subsequent caution was understandable, given its experience with reserve overestimates on Vietnam's Dai Hung.

If anything, the partners appear to be driving the project forwards. Petroz and Santoz, which hold combined stakes of over 36%, announced their boards' approval for the development before BHP had issued its own statement (BHP did not appear to expect project sanction before year-end). According to Petroz' managing director Rod Brown, one of his company's key motives was to generate cash from the oil to fund its share of the Bayu-Undan gas condensate field.

Exploration upturn

Dry runs on wells on other ZOC permits in 1994 by Enterprise, Sagasco and BHP meant that hopes were not sky high for Phillips' campaign that December. The company's third of three commitment wells on ZOC A Permit 91-13, Bayu-1, was testing a structure on the south-east flank of the Flamingo High in 236ft of water.

However, surprising gas shows were encountered through a 155 meter gross gas column in a stacked sequence of Montara and Plover sands. Four DSTs flowed cumulatively 90mcfd and 5,250b/d of condensate through a 1-in. choke. It then emerged from mapping that Bayu was a structure 160sq km in size, also extending into BHP's PSC 91-12.

With the mandatory exploration phase now over, these two permit holders and four other joint venture groups elected to pursue a second exploration phase for their PSCs, which resulted in the steady stream of successes on Bayu-Undan. In June 1995, BHP and partners made their breakthrough in the southern portion of 91-12 with Undan-1.

This well, 9.6km northwest of the Bayu-1 discovery, delineated a 139 meter gross hydrocarbon column, also in stacked Montara and Plover sands and with the same gas-water contact as that intersected by Bayu-1. Two DSTs through 3/4-in. and 1-in. chokes flowed 64mcf/d and 4,000b/d of condensate in total.

After that, the hits kept coming:

* November 1995, BHP suspends Undan-2, 5km south-west of Undan-1 and 11.5km west of Bayu-1: the well flows up to 35.4mcf/d and 2,200b/d of condensate, having intersected a 105 meter gross hydrocarbon column

* December 1995, Undan-3 suspended after intersecting a 136m gross hydrocarbon column over an interval between 2,996 and 3,137 meters deep: gas-water contact identical to all previous Bayu-Undan wells

* December 1995, Bayu-2, 6.4km north of Bayu-1, tests 35mcf/d and 2,100b/d through a 1-in. choke from a 50m gross hydrocarbon column in late Jurassic sandstones

* April 1996, Bayu-3, on the north-east flank of Bayu-Undan, is drilled in an area where a large seabed channel complicates seismic interpretation: although the gas column is smaller, at 60 meters, sands prove to be of good quality

* May 1996, Undan-4 on the western flank of Bayu-Undan intersects a 43m hydrocarbon column in the Upper Jurassic Flamingo and Middle Jurassic Elang formations: the top two Elang sands are tested, but quality is below previous Undan tests with only the second sand flowing significantly at 8.63mcf/d and 542b/d through a 1-in. choke

* May 1996, Bayu-4 appraises the most northerly fault block on ZOC A 91-13, proving up additional reserves through a four-zone DST, but within very moderate quality sands.

The Phillips-led venture should be well under way with a fifth well on the south of their structure, and BHP should also have started appraising the westerly Trulek extension. Another structure on this side of Undan, Henkip, may be appraised next year, depending on rig availability. BHP has also initiated a 1,200km seismic survey over the Undan area using the Nordic Explorer.

Development options

Bayu-Undan's location, in an area adrift from infrastructure and 185 miles off the northwest coast of Australia, makes two standalone developments impractical. Both sets of permit partners have accepted the necessity for a unitized development, probably costing $1 billion, although formal agreement has still to be finalized.

British analysts Wood Mackenzie estimate gas reserves for the entire field at 3-5tcf, with a liquids potential of 120-250MM bbl, depending on the recovery method selected. Wood Mackenzie believes 50-60% of reserves could lie on the Undan side, with Bayu holding 40-50%.

Hardy Oil & Gas, a partner in the Phillips venture, stated in its 1996 report that production would be feasible within five to seven years. The platform hardware selected will depend on results of separate one-year studies by Phillips and BHP into gas/liquids extraction techniques. The optimum method should be selected next summer.

BHP has chewed over a number of options, including liquids stripping, offshore LNG processing or a combination of the two - gas recycling followed by blowdown. According to Wood Mackenzie, gas stripping would provide quick cashflow while circumventing the thorny issue of gas marketing. Liquids stripping, depending on the final reserves estimate, could theoretically be implemented within three years.

Aker NC has just been commissioned by BHP to perform a 12,000 manhour conceptual study, with other companies, for concrete gravity base structures for four large LPG tanks which would be stationed on a coral reef in 30 meters of water on Bayu-Undan. This might not accord with the initial feasibility studies, thought to favor two FPSO vessels for gas processing and onboard LPG/condensate storage, as well as two unmanned platforms providing gas compression and reinjection.

BHP has also developed its own in-house proprietary LNG conversion technology, which could be housed on reef-based tanks or an FPSO. Phillips operates the world's first Pacific-based LNG export project at Kenai, Alaska, and is though to prefer installation of a fixed offshore facility for Bayu-Undan with a two-train LNG plant on land near Darwin.

Kenai has been operating continuously since 1969, using Phillips' proprietary conversion technology, Cascade. With this method, three chilling cycles, using propane, ethylene and methane, are employed to cool the purified gas until it liquefies. The gas is then subjected to a reduced pressure to produce LNG at approximately atmospheric pressure.

At a temperature close to -259degF, the LNG is then transferred to three heavily insulated, 225,000bbl storage tanks with some of the LNG boiled off to maintain the rest at its liquid temperature, and also to fuel the refrigeration compressors. Finally, the LNG is loaded onto tankers for export.

For Bayu-Undan, the fixed offshore facility might carry onboard processing and facilities for loading offshore the condensate and/or LNG. Gas would then head 450km to the site near Darwin via a pipeline. Whatever development method is chosen, Wood Mackenzie is assuming at this stage an 11-year field life.

Further prospects

Darwin is also seen as a support base for the Woodside-led Laminaria/Corallina oil development, just outdside the northwest tip of the Zone of Cooperation. In adjoining ZOC Permit 91-01, BHP made a small oil discovery earlier this year that tested 1,350b/d in Middle Jurassic sands. Conceivably, this could be tied back to Laminaria/Corallina.

Other ZOC wells drilled to date have yielded oil and gas traces or nothing whatsoever, as was the case this spring with Enterprise's Wallaroo-1 in ZOC A 91-14 which was targeting the Plover objective. Twelve wells are expected to be drilled during 1996, the first batch after the mandatory Timor Gap exploration phase, and Wood Mackenzie forecasts a similar number next year.

Five new PSCs are expected to be confirmed shortly in the `A' contract area. One was being negotiated for block 95-18 in the north, close to the Kelp structure drilled by Woodside in March 1994. This was a dry hole with the logs recording high resistivity. The new tenants should be a five-company consortium led by Mobil, operating from offices in Darwin. According to one of the partners, Statoil, their aim is to find gas reserves to form the basis for an LNG plant.

Wood Mackenzie's Alastair Syme points out that all the 91-12 and 91-13 plays identified so far have "the same age structure and tilted fault blocks". If other consortia are to have success, he suggests, they should perhaps target less conventional ZOC plays in water depths below 200 meters.