Low profile project springboard to deepwater for independent

OPERATOR PROFILE: Tuskar Resources

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Th 0300osobe1
Block OML 110 has six sizeable prospects, in addition to the Obe discovery in the north.
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Nigeria's indigenous oil industry assis tance program is stirring activity on fields forsaken by the majors. Local companies and western independents are teaming up to produce shallow water minor oil deposits close to shore. The development process can be laborious for teams with stretched resources, and the short-term rewards often seem limited. But the object of the exercise may be longer term.

This was the case with the Tuskar Resources/ Allied Energy/Cavendish combine which recently achieved first oil from the Obe Field in block OML 110 (formerly designated OPL 453). The field lies at the northern, shallow water tip of the license. It was discovered by Japex in the 1970s, then abandoned following an unsuccessful appraisal well. Subsequent operator, Conoco, also made little headway with a follow-up well.

Conoco and its indigenous partner in OPL 453, Cavendish, then acquired 2D seismic over the license's deeper water plays to the south and west. Analysis pointed to five or six significant prospects, but Conoco decided to exit the block in 1995. In its place, Cavendish brought onboard the Irish-based independent Tuskar, which at the time relied on limited oil production from its share of a North Sea field.

These two had the will, but not the wherewithal, to pursue development of Obe. The solution came in 1996, when another Nigerian-owned independent, Allied Energy, farmed-in with 40% of the block, in exchange for a 60% stake in Tuskar. Allied became operator with Tuskar acting as its technical partner. The latter's headquarters were subsequently moved to Houston. From the outset, Allied had its eyes on the block's deeper water plays, with Obe viewed as a necessary step towards that target.

Marginal solutions

Obe lies in 65 ft of water. According to Tuskar's Managing Director Gene Manson, Japex had encountered oil in the 7,000 ft depth zone. "They had a good test, then stepped out with a second well to the south - but it completely missed out on production, so they gave up on it." Conoco's follow-up well targeted the 6,500 ft zone, which tested 1,850 b/d.

In 1997, Tuskar drilled a fourth well, which confirmed the location of the two productive zones. The prognosis was a straightforward, 15 million bbl reservoir with an anticipated productive life of around five years. The problem was settling on an economic solution for a field this marginal. The partners' first thought was to tie production south to Chevron's Parabe platform in OML 95. However, that facility had no spare capacity at the time. A dedicated, minimal platform was then considered, as were a host of FPSOs. But lease terms for a vessel in such shallow waters in those days looked beyond the partners' economic capability.

Subsequently, progress faltered. "In the past year, however, we came across Brovig Offshore," Manson explains. "They owned two smaller storage capacity FPSOs designed for extended well tests, particularly in the North Sea. Both their vessels were idle, so they were anxious for work."

Small FPSO units

A deal was struck last July whereby Brovig's Crystal Sea would be contracted to produce Obe for up to five years at "an economically attractive rate", according to Manson. Production would come initially from the re-entered Obe-4 well, with Brovig funding the extended test and subsequent completion. It would be reimbursed for this expense from production revenues. Oil trader Glencore International contracted to purchase the field's entire output for one year, which would be offloaded in 50,000 bbl parcels from the Crystal Sea.

Obe-4 was re-entered in November, flowing initially at over 7,000 b/d. That rate was expected to stabilize to around 5,000 b/d. Dependent on performance, a location for a second producer (Obe-5) would be fixed with a view to doubling daily output to 10,000 bbl. Tuskar was negotiating with Noble Drilling for one of its locally idle jackups to drill the well in March. Day rates in West Africa are down to $30,000 at present, which further aids the project's economics.

Production from Obe would have started earlier but for a couple of delaying incidents. A caisson had to be fitted unexpectedly over the conductor piles on the re-entered well, for reinforcement purposes. Also, a member of staff was "detained" by a group from a local community. "This was resolved in the customary manner," Manson says. The upside of these delays is that production has coincided with the recent oil price high.

The partners' attention is now switching to the block's deeper water potential. They plan to take advantage of currently low rates for seismic vessels by commissioning a 3D survey over a 550 sq km swath across the six prospects identified by Conoco's 2D campaign. According to Manson, independent evaluation suggests potential combined reserves of 1 billion bbl. The new survey should take two months, with the processed data available for analysis mid-summer. An exploratory well could follow shortly afterwards, with a new partner hopefully co-opted by then to share the expense.

Manson is upbeat, based on recent well results in adjoining blocks. Chevron made a discovery in the adjoining block OML 95 to the east, and Agip has a discovery in adjoining block OPL 316 to the west. "The Agip discovery appears to be a nice-looking structure with a very good flow rate. "What's interesting is that this structure is very similar to the Conoco OPE prospect on OML 110, which was drilled with oil shows, but could not be fully evaluated because of drilling problems."

Should drilling confirm expectations, the partners may consider bringing the Crystal Sea across for an extended test. Production from Obe could then conceivably be re-routed to the Parabe platform, which now has spare capacity.

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