It has been nearly a decade since Woodside Petroleum struck oil at Enfield, 50km offshore from Exmouth in Western Australia.
It was a substantial find – the reserves were eventually estimated at 125 million barrels – and heralded the beginning of a new oil province. But Enfield proved to be a heavy, sluggish crude, regarded as barely economic to develop at the then prevailing $US20 per barrel oil prices.
But these days nobody talks about Enfield – or any of the other four developments planned in the Exmouth Sub Basin – as being marginal.
The quadrupling of oil prices and technical lessons learned by Woodside at Enfield (the $A1.5 billion development was approved in March 2004 and produced first oil in July 2006) have opened up a large field of opportunities.
By early next decade, there should be five floating processing, storage and offtake vessels working off the North West Cape, built by three different operators at a total cost of nearly $A6 billion. Far from being a borderline proposition, the Cape is now seen as the latest Great White Hope to temporarily halt the continuing decline in Australia’s oil self-sufficiency.
All five projects will produce relatively similar types of heavy crude. One practical difficulty is that the oil doesn’t flow easily. Enfield, for instance, uses gas to help lift the crude to the surface.
BHP Billiton’s $US760 million Stybarrow development is also expected to use gas lifting. It may also require some form of heating to assist the oil flow, as the field, in water 825m deep, is the deepest oil development undertaken in Australia yet.
Marketing is another hurdle. Enfield’s crude has been well accepted, but there is “uncertainty over the take-up of additional heavy crude from the region”, according to one industry source.
Mind you, with Tapis crude selling at $US100 a barrel at press time, even a substantial discount to the benchmark crudes won’t break the bank for new projects.
And BHP denies there is a problem: “As a marketable crude oil, Stybarrow will be sought after because of its blending characteristics, its low sulphur, low contaminants and moderate acid, making it a crude oil of choice for North Asian customers,” the company says.
BHP Billiton: Stybarrow and Pyrenees
Woodside and BHP are the Exmouth Sub-basin’s key operators, while US-based Apache is snapping at their heels. BHP’s Stybarrow began production in November – three months earlier than original forecasts.
A 50:50 joint venture with Woodside Petroleum, the field is expected to take three months to ramp up to around 80,000 barrels per day, a BHP spokeswoman said. Operator BHP is more bullish than Woodside, which predicts a six-month ramp up to a plateau of around 50,000-60,000bpd.
Woodside’s caution may be due to its experience at Enfield, where technical problems late last year crimped output at the venture. Stybarrow’s peak production will last for roughly one year after start-up, with a “steady decline after that,” the BHP spokeswoman said, adding that the field’s forecast life is 10 years.
The next project in line for BHP is Pyrenees, approved in July at a cost of $US1.7 billion. The venture, which includes Apache, will be capable of producing around 96,000bpd from the first half of 2010.
BHP Billiton is purchasing an existing FPSO hull, which was built by Samsung in Korea in 2007. Additional conversion, installation and fit-out activities will be done in China by MODEC, a major provider of FPSO systems.
The FPSO, a disconnectable, double-hulled Suez Max tanker, will have storage capacity of 900,000 barrels while the topsides will be able to process around 96,000bpd.
After Pyrenees, BHP’s potential share of production in the Cape region may briefly touch 100,000 barrels of oil per day. This compares with the Gulf of Mexico in the United States, where BHP’s production is due to move from 12,000 barrels of oil equivalent per day to 100,000boepd next year.
BHP says the new US and Australian oil projects will launch a “step change” in production after its output in the fiscal year ending June 30, 2007, held steady at 116 million barrels of oil equivalent.
However, the new developments are in a sensitive area, only a few kilometres outside the Commonwealth’s Ningaloo Marine Park, which extends 20km from the North West Cape coast. Pyrenees is the closest, roughly 15km north of the Commonwealth park border.
The FPSOs are visible from the lighthouse at Exmouth, a tourist town favoured for whale watching and fishing expeditions. In fact, migrating humpback whales will pass close to some infrastructure as Pyrenees is roughly in the middle of the whale “track”.
But BHP says the project won’t unduly interrupt the migrations – the humpbacks just swim around any obstacles.
Woodside: Enfield and Vincent
In Exmouth, the possibility of oil spills from one or more of these new developments is a worry for residents.
Woodside has installed an oil spill response facility at the town and says it is training locals to use the equipment. Computer models indicate that the chances of a spill reaching the shore are low. It would need to be a big leak, compounded by highly unfavourable weather conditions.
The North West Cape is a vital cog in Woodside’s growth plan, which sees oil as a funding mechanism for its LNG developments – namely the $12 billion Pluto project.
“Woodside is developing a significant oil production hub off North West Cape,” said Steve Hall, Woodside’s general manager, Greater Enfield Area.
“This hub is particularly good business for Woodside, given current high oil prices, and will continue to provide cash flow to help fund Woodside’s broader aspirations of becoming a global leader in LNG production and supply.”
According to Hall, Woodside has taken a “leadership role” in developing the region’s production facilities. Design features for Enfield that have set the lead for others to follow include a double-skinned hull for the FPSO, a retractable offtake hose reel and improved deck lighting to reduce light pollution and visibility from shore, he said.
Enfield will be followed by the nearby Vincent development, due to start production in the third quarter of 2008 at a cost of $US720 million. Both projects are 40% owned by Mitsui.
Woodside originally planned a joint development of Enfield and Vincent, but eventually decided on separate projects. Enfield was deemed the “easier” of the two. But it soon ran into problems, probably because not enough drilling was done to understand the reservoir.
After hitting its proposed 70,000bpd production target, the project fell away quickly due to water and sand ingress, and a well was shut down in October 2006.
Woodside was forced to drill a sidetrack from the producer well, along with a water injector. By the end of September 2007, the field was producing at around 55,000bpd and should increase once pressure support from the new water injector is established. But the improvements are unlikely to push output back up to the original 70,000bpd target.
Vincent – where peak production could reach 80,000bpd – is a challenging project because of the unusual reservoir, which is shaped like a huge pizza.
One source likened the development to “draining a footy field of water”.
The project’s budget may come under pressure because of the numerous long horizontal wells required.
Vincent is slated for eight production wells. But these will be “dual lateral wells”, providing 16 production sources from eight well heads. The development has a 15-year life, though Woodside and Mitsui have only approved the first seven-year phase. The FPSO will be leased from Maersk, which is modifying the double-hulled vessel in Singapore, and is due to sail south in the first half of 2008.
Apache: Van Gogh
Meanwhile, Houston-based Apache is playing catch-up with the Australian majors, firstly via its proposed $US500 million Van Gogh development.
Apache received a boost in June when Theo 3-H flowed 9694 barrels of oil per day in a test of the first horizontal well at Van Gogh. The company was planning to drill 18 additional long-reach horizontal laterals by late 2007 with first production anticipated by the end of the first quarter of 2009.
Apache, which claims to be Australia’s most active offshore operator, is expected to reap around 20,000 barrels per day net from Van Gogh when it comes on line in 2009. Apache owns 52.5% of the development, with Tokyo-based Inpex holding 47.5%. Van Gogh’s FPSO, MT Kudam, will have processing capacity of 63,000bpd and storage capacity of 620,000bpd.
What next?
The new North West Cape fields will help shore up Australia’s declining petroleum liquids output, under pressure in recent years because of rising costs, few major discoveries, and declines in traditional fields such as Bass Strait.
In September, the Australian Bureau of Agricultural and Resource Economics said the nation’s crude oil production in the fiscal year ending June 30, 2008, is forecast to increase by 6% to 30.4 gigalitres, up from 28.8GL previously. Increased production from new fields such as Vincent and Stybarrow will contribute to the increase, according to ABARE.
Longer-term, gas may also be a focus for the North West Cape, with BHP sitting on the Macedon discovery.
BHP floated a concept a few years ago that would have pooled the various gas accumulations in the region for a domestic project. But the plan faltered on the then low gas prices of around $2 per gigajoule.
Prices are now around $7/GJ, making a domestic gas venture more feasible. However, gas will probably only be seriously considered once the oil starts dwindling 5-10 years from now.
First published in the November 2007 issue of Petroleum magazine
