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In Deepwater West Africa, the Italian major is the dominant producer of small fields

With its continuous production of the 80 Million barrel Abo field and its focus on first oil from Oyo field, Agip, the Italian major, is on course to become the dominant producer of marginal fields in deepwater West Africa.
This is an unusual role for a major company, especially one of those who came in early in the global deepwater adventure.
Agip drilled two more wells on the Abo field(OML 125, Nigeria) in the last three months, targeting deeper reservoirs, just about the time that Shell decided that the entire acreage was not worth its while, and sold its own stake to Oando, the Nigerian owned minnow. When the two new Abo wells are hooked up in November 2008, the field would be doing 25,000 BOPD. Agip is even looking at other opportunities, not much larger than Abo, in this area.
When energy analysts, in the 90s, branded deepwater West Africa “the playground of the majors”, they primarily meant that independents were not invited to the party. In those analyses, it was regularly pointed out that the discoveries, oftentimes turbidite complexes, were large structures, with forecast production averaging 100,000 BOPD. These forecasts have been proved correct, as the flagship fields - Girrasol and Dalia in Angola and Bonga and Erha in Nigeria, came on stream in the last five years. Bonga, for one, has produced well in excess of 200Million barrels in the last 30 months.
But something happened on the way to Rotterdam.
Midsized independents as well as significant minnows started farming into the majors’ acreages and sooner than later, started acquiring deepwater acreages of their own. In the event, they started encountering respectably sized discoveries (at least 250MMBO) in excess of 1,000 metre Water Depth and even going forward to develop them.
In the meantime, as some of the earliest geologic assumptions failed on test, the biggest companies started walking out of acreages and projects deemed uneconomic.
Shell left Angola in part because of the painful realization that the Bengo field, on which it had pinned so much hope early in the day, started looking very uneconomic(pancake thin reservoirs, high GOR, etc). BP, which had gone to Nigeria in alliance with Statoil, walked out of the country as exploration well after exciting exploration well proved a duster. Statoil decided to stay, largely because somewhere along the line, Chevron discovered Agbami on the western border of one of its leases, and that huge field extends into its own acreage (now OML 128).
The story of deepwater West Africa is that the majors stay away from small fields. In Nigeria and Angola, it is considered uneconomic –by the major companies-to develop a field of less than 120MMBO mean estimated recoverable reserves, in 500 metres of water. For this depth of water, the rig rates have always been regarded as high.

But Agip’s adventure in Nigeria has turned out to be the exception.
At the time it took the decision to produce Abo field in 2000 the pool had an estimated 70MMBO (Million Barrels of Oil). Today the estimates are 58MMBO.
The Oyo field, which Agip farmed into as technical operator in 2005, holds about 100MMBO (mean, estimated recoverable reserves). It was the first deepwater discovery in Nigeria (Allied Petroleum, 1995) Statoil was Allied’s technical partner when Oyo was discovered. The Norweigian operator could not build a business case for investment in the field’s development. “At that time (of $15-20 per barrel crude oil prices),the threshold was 250MMBO”, say sources familiar with the situation. “If your reserves were not up to 250million barrels no one would finance your project”. For a long time,  no one else wanted to touch the field, and Allied Petroleum was left holding an empty calabash when Agip walked into the project in 2005.
By 2006, it had drilled Oyo 2.  As of this writing, Agip had drilled two more wells and plans to drill two more. Of the six wells to start with, one is a water injector, and another, a gas injector.
No one in Agip’s headquarters in Port Harcourt would want to talk about the reserves, or the expected production rates, but Allied Petroleum has gone to press with the news that peak production would be 25,000BOPD.