Jeremy Beckman
Editor, Europe
Austria's leading independent, OMV, is looking to double its global production to 160,000 boe/d by 2008. Much will depend on its activities offshore Australia and New Zealand, where the company is preparing to invest heavily in new development projects.
Pre-1999, OMV's upstream focus was largely onshore, and too heavily weighted to under-explored, third world acreage for the board's liking.
"We wanted a better balance in terms of political risk," Helmut Langanger, head of the exploration and production division in Vienna, said. "Of our various bases, only Austria and the UK were OECD countries."
During the subsequent review of "first-world" opportunities, North America was ruled out.
"Too many of our competitors were already established in the US," Langanger says, "especially offshore. And the Western Canadian basin was very mature, even though we had been there before as a partner during 1987-93. Then our E&P team suggested Australia, which did not seem to be as mature as the Gulf of Mexico or the UK, nor as regulated and protectionist as Norway was at that time."
What Australia did offer was a stable political and fiscal regime and only a few active major oil companies, drawn mainly to the big gas plays on the North West Shelf and in the Bass Strait. This was leaving the way largely clear for small to mid-sized independents such as Santos, Woodside, and Apache to tackle Australia's largely stranded oil accumulations.
"And we soon found out that the smaller companies lacked the financial muscle to apply modern exploration skills to these fields," Langanger says. "We felt we could apply the necessary technologies, based on our experience as an operator onshore Austria, to oilfields off western Australia in the size range 20-50 MMbbl. We also decided to concentrate at first on proven provinces."
Late in 1998, OMV set up an office in Perth, and was awarded two exploration licenses in the Carnarvon Basin. "But we soon realized that building a meaningful portfolio through our exploration efforts alone could take five to six years. We needed a shortcut. This led to our hostile takeover bid for Cultus Petroleum."
Cultus, which was listed on the Sydney Stock Exchange, was an established company with two production interests in the onshore Cooper block units in South Australia and the aging Jabiru/Challis oilfields in the Timor Sea, off the Northern Territory. But its real assets were undeveloped, in particular its 30% stake in the Maari oilfield offshore New Zealand's North Island; the Tenacious discovery in the Timor Sea, and the Patricia Baleen/Golden Beach gas fields in Victoria's Gippsland basin.
The takeover battle lasted five months, during which Cultus' share price first rose (following the results of a positive well on Maari), then plunged as the oil price fell. One potential concern for OMV was Cultus' stake in Shell's Cornea discovery in the Browse basin, viewed initially as world class, then downgraded to sub-economic. But OMV quickly reached agreement with the Energy Ministry in Canberra to fulfill its commitments relative to the Cornea block via exploration elsewhere.
"The government was – and is – happy to encourage newcomers, especially of our size," Langanger says, "and we felt we could be as successful as, say, Apache had been, although they had focused heavily on the Carnarvon basin."
Nine Cultus employees took up OMV's offer to relocate from Sydney to Perth. The operation has since grown to a technical/commercial team of 50, supervising all of OMV's interests around Australia, which now include production offshore Victoria. The company's current development focus is on gas development in the Gippsland basin and oil in the Timor Sea.
Timor Sea prospects
Jabiru and Challis/Cassini were two mid-sized oil developments distributed under licenses AC/L 1, 2, and 3, brought onstream respectively in 1986 and 1989, each employing FPSOs offloading to shuttle tankers. Cultus picked up an 18.75% interest in both projects when it acquired Esso Timor Sea for A$30 million. Today, the fields are operated by an Australian company, Coogee Resources.
"When OMV bought Cultus, both fields were forecast to wind down completely within four years, but in fact they are still pushing out 7,000 b/d," says Langanger. "Even with our share, that represents a healthy cash flow, at the current oil price of $27/bbl. We estimate two to three years further production in both cases."
OMV had also inherited operatorship of the nearby Ashmore/Cartier P17 permit, which included the Tenacious oilfield discovery. In early 2001, it drilled its first well as an Australian operator on this acreage in partnership with Japan's Cosmo Oil and Australia's Woodside Petroleum. This led to discovery of Audacious, 20 km northeast of Tenacious in 165 m of water. The well tested over 9,000 b/d of 55° API oil, which was above the design capacity for the test.
Both the finds are potentially commercial, and there are numerous other small accumulations, prospects, and leads in the area that need to be investigated, according to Gerald Winkler, vice president of EP technologies and operations. Tenacious is 14 km from the Jabiru floater, which is in good condition, he says.
"We are looking at using these facilities as a main center for our fields," Winkler says, "but the problem is that there is no alignment between the concession holders of the various satellites and the Jabiru/Challis owners. This also affects us in terms of tariffs."
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Gippsland gas drive
Patricia Baleen is a small, dry gas field situated 23 km off the Victoria coast in 55 m of water. The field was discovered in the 1970s. Cultus had been 100% equity holder of the surrounding VIC/RL 5 lease since 1996. The following year, Kværner performed an engineering feasibility study based on a monotower with extended reach wells. However, environmental activists claimed this would spoil views of the coastline. Also, as Winkler points out, strong underwater currents in this area militate against use of a monotower.
During 1999-2001, OMV as operator acquired new 3D seismic over the field and drilled an appraisal well, confirming its southwest extent. Recoverable reserves were estimated at around 70 bcf, mostly lying within the Gurnard formation of the Gippsland basin. Development was authorized in August 2001 to coincide with commissioning of the new Eastern Gas Pipeline, operated by Duke Energy, which would connect the main gas networks in southeast Australia. On behalf of the joint venture, OMV agreed to sell 59 PJs from Patricia Baleen to Energex Retail, a Queensland state-owned utility, with an option to supply further gas at a later stage.
The development plan was based on subsea completions, including 500-m horizontal sections, with two wells being drilled as "snake" wells, following the challenging shape of the reservoir. Both have subsea completions, a first for the Gippsland basin. The two subsea wells produce around 16 bcf/yr through a 24-km subsea pipeline, followed by a beach crossing section (another first in this area) to a new processing plant at Orbost. This site also controls the offshore facilities.
A union recognition dispute delayed start-up by a few months to April 2003, and the eventual development cost was A$100 million. Patricia Baleen represents OMV's first venture as an offshore production anywhere. Its co-venturers are Trinity Gas Resources and Santos, Australia's largest gas producer. Production is currently close to 40 MMcf/d, with field life estimated at up to 10 years. All engineering and conceptual design work was performed in Perth, while operations are managed by a local contractor, Upstream.
Around 50 km southeast of Patricia Baleen is Sole, a gas discovery also operated by OMV. The partners are working on development concepts, following a successful second well on the field in July 2002. Sole could be produced from 2005 onwards, possibly again with subsea completions. Another prospect is Golden Beach, a small gas discovery in the western Gippsland basin and within tie-in reach of the Duke trunkline.
"We are interested in acquiring more permits in this area, and establishing a larger presence," says Langanger. As off western and northern Australia, the authorities are keen to see more action in the Gippsland basin, with even 500 bcf fields such as Kipper lying dormant, due to operator inertia.
"One difficulty is that there are not too many drilling rigs based locally," Langanger says, "so you must always hunt around for someone to share mob/de-mob costs. Often rigs have to be brought in from Singapore or northern Australia, a distance of 8,000 km, which pushes mob/de-mob costs up to $A8-10 million. The same applies offshore New Zealand."
Before buying Cultus, OMV was part of a consortium awarded the Western Australia permit 292 in the Carnarvon basin. Two prospects were identified for drilling, following seismic analysis, but both subsequent wells were dry. In June 2001, the company was awarded two permits as operator in the same basin, WA-308 P and WA-309 P.
"We committed to a three-year program," says Winkler, "comprising seismic acquisition, processing, re-processing and interpretation. And if we apply for a fourth-year extension, that carries a one-well obligation. The nearest producing field is Agip's Woolybutt. Part of our strategy is to build up comprehensive data sets across this region. We have seen a couple of interesting features from existing seismic."
Langanger agrees: "There are plenty of leads in the 30-50 MMbbl range, and this was our original target when we entered this area. If you do find oil here, the reservoir properties are good for high flow rates – 5,000-6,000 b/d is not uncommon. And the local crude is also good quality, selling at US$1/bbl above standard Brent prices. Our target is to drill around four to five wells per year around Australia. Our budget is around A$10-12 million a year, with an average working interest in a license of 30-40%."
OMV's production in Australia has risen to 6,000 boe/d, with the contributions from Patricia Baleen. The next step up will depend on resolving outstanding commercial issues in the Gippsland basin and the Timor Sea. As for buying existing production assets or development prospects, this is not so easy at current oil prices, Langanger points out. Woodside, which is one of the more prolific operators off western Australia, also needs cash flow from all its properties to expand its international portfolio.
"And we don't want to buy fields with only three or four years field life, and abandonment liabilities," he says. "If we do make further acquisitions, they will be in the vicinity of our existing licenses or to form the basis of a new hub."
In New Zealand, all OMV's offshore interests are concentrated in the Taranaki basin.
New Zealand entry
In September 2002, OMV secured its first production from New Zealand by buying 10% of the Maui field in the Taranaki basin from operator Shell. Maui, which has produced gas since 1979 and oil since 1996, is the country's largest field in service, and also its sole offshore development to date. The production infrastructure comprises two platforms and an FPSO, with 26 production wells, oil and gas sea lines, a processing complex onshore in Oaonui, and an overland pipeline from Oaonui to Auckland. All the facilities are in good shape, according to Langanger. Around 75% of production is gas, the remainder being oil, condensate, and LPG, with a net benefit to OMV at present of 8,000 boe/d. Todd Petroleum Mining Holding, with 6.5%, is also a partner in the development.
According to a report issued this January by US-based consultants Netherland, Sewell and Associates, Maui's gas reserves had been downgraded, with 367 PJs remaining as of Jan. 1. At current rates of depletion, the field would cease production by 2007, not 2009, as had been anticipated.
Analysts Wood Mackenzie commented that failure to add new gas sources could drive the country more toward geothermal and oil-fired energy. However, Langanger maintains that Maui – in concert with Pohokura – could supply gas to the mainland for a further 10-15 years. Pohokura, in offshore permit PEP 38459, is New Zealand's largest undeveloped gas-condensate field. OMV acquired a 35.86% stake last year through its acquisition of German independent Preussag Energie and is currently looking to scale back this interest to 26% via an agreement with Todd, which will also then hold 26%. Shell has the remaining 48%.
Recently, the Commerce Commission authorized the partners to jointly market and sell their shares of the gas. However, it also imposed three conditions:
- Production must start by mid-2006, and plant production capacity must be at least 60 PJs/year
- Any assignment of interest by one of the participants would require the Commerce Commission's approval
- The partners should not prevent further onselling of the gas.
"The impact of these conditions on the development is currently being assessed," Langanger says. "However, front-end engineering design is ongoing for Pohokura. We hope New Zealand's master development plan for energy will be ready by the first half of 2004 so that we can also get approval for our development scheme. The field lies just 2.3 km offshore. Wet gas will be sent to shore for processing and extraction of natural gas liquids. Development will likely involve two unmanned platforms, each with five wells."
OMV's other main asset in New Zealand is Maari, an oilfield situated 35 km south of Maui and 120 km southwest of New Plymouth, in 100 m of water. OMV is operator with 69% interest. The partners are Todd, Sydney-based Horizon Oil, and Delta Oil Taranaki. "We already knew about this field when we acquired Cultus," says Winkler. "They had come up with a new play concept, which led to a successful exploratory well being drilled late in 1998."
This January, the partners drilled Maari-2, in an attempt to better appraise the reservoir's Moki formation. The well, drilled by the Diamond Offshore semi Ocean Bounty, indicated the presence of a 41-m oil column. More work is needed to delineate the shallower M2A sand level and the Mangahewa formation, and other prospects such as Manaia, southwest of Maui, and Pike.
"The main thing is, this seems to be an oily area," says Langanger. "We currently estimate 150 MMbbl in place, with up to 50 MMbbl recoverable. For offshore New Zealand, that could be significant. Conceptual engineering relative to the development is progressing. Once the concept is selected, the commercial viability of the project will be assessed."
In an adjacent offshore block (38472), OMV is operator in a 50-50 partnership with New Zealand Oil & Gas Geophysical. Geological, geophysical, and seismic studies got under way this year. OMV also has 25% of Taranaki basin blocks 38481/2, both operated by Shell. Early this year, the survey vessel Polar Duke acquired 2D seismic over these blocks.
"All are in an oil and gas-prone area," Lang-anger says. "We want to capture as much interesting acreage as possible in the Taranaki basin. For the time being, we will stay in this area, but we don't rule out bidding for E&P acreage in other basins offshore New Zealand, once we have become a major producer."
OMV has transferred some of its geophysical reservoir engineering and seismic imaging techniques, honed mainly in the Vienna Basin, the Iranian overthrust, and offshore Vietnam, to its Australasian activities.
"We were asked to build the reservoir strata model for Maari before we became the operator," Winkler says. Pre-stack depth migration has been used to improve reservoir analysis in Australia, and remote sensing interpretation and geological mapping capabilities have been applied in the North West Shelf to link subsurface data with surface features such as faults and anticlines. Acoustic and elastic impedance inversion of 3D seismic cubes has also been deployed to improve assessment of reservoir thickness.
Since 1999, the company has also amassed substantial acreage positions along the UK Atlantic Margin, the Black Sea, North Africa, and the Middle East.
