NIGERIA - The Oso Field.

It was not until 1988 that MPN decided to develop Oso, on the basis of a 1986 MoU guaranteeing a minimum profit margin of $2/b and confirmation that condensates were excluded from OPEC's production quotas. The World Bank and its IFC funded the Oso JV. About 89 km south-west of the Qua Iboe terminal and 67 km from the Bonny island gas processing system, Oso is a giant gas field by African standards with a sustainable production capacity of 100,000 b/d.

Oso has had enough reserves to recover at least 500m barrels of condensate in a 20-year production period and to still have a deposit of about 3,500 BCF. From the remaining gas, MPN can recover liquids, including LPG. As the gas is forced to the surface, it cools and takes the form of condensate, having the qualities of an almost sulphur-free oil. Gas associated with condensates is then re-injected into Oso for an important NGL recovery system, Phase-II, which came on stream in November 1998.

Phase-I of Oso's development cost $900m. When the go ahead was given, it was agreed its commercial production was to be for 20 years. It was estimated this would yield $12 bn to NNPC and MPN and that the partners should recoup their investment within two years of production (see background in Vol. 57, Gas Market Trends No. 6).

MPN has a 51% majority in Oso's Phase-II for NGLs, with NNPC holding 49%. This has resulted from NNPC's failure to fund its share of Phase-II costs and Western financiers' perception of high risk in Nigeria. (NNPC and MPN could no longer get funding from commercial banks and development agencies. Instead, MPN in 1996 raised $300m in US commercial bonds secured by future gas sales commitments. MPN has since proposed that NNPC also reduce its stake in favour of the US major in its main JV, because of NNPC's cash problems. But Abuja has turned it down).

Phase-II came on stream in November 1998 and cost $860m. Its 50,000 b/d of NGL output was reached in March 1999. NGL is stripped out of 600 MCF/d of gas coming in equal volumes from Oso and Usari field nearby. Dry gas is re-injected. The liquids, pumped to a fractionator on Bonny island via a 67 km pipeline, are separated into 27,000 b/d of propane, 14,000 b/d of butane and 9,000 b/d of pentane-plus. In Phase-II, 350m barrels of NGLs were to be extracted over 25 years without affecting Oso's condensate stream. The NGLs are mostly exported, with some sold locally.

MPN in early May 2003 declared force majeure on exports of Oso condensate after it was forced to shut in production following a fire the previous week at the Oso platform. About 95,000 b/d of condensate and 45,000 b/d of NGLs were shut in to allow full investigation and restoration of the facility. Operations and exports were resumed in July 2003 (see background in Vol. 61, Gas Market Trends No. 6).

Apart from the two JVs, ExxonMobil has PSCs for offshore tracts, where water depths exceed 1,000 metres. These include Erha, with 500m barrels of recoverable oil which Mobil found in 1999. In this ExxonMobil holds 56.25% and Shell holds 43.75%. Bouygues Offshore, the French subsidiary of the ENI group's engineering unit Saipem, has been contracted for the $700m FPSO vessel for Erha. Bouygues has subcontracted the 2.2m-barrel hull to Hyundai of South Korea. The field lies in 1,200 meters of water.

Under joint operation agreements signed in May 2002, ExxonMobil is exploring OPL 214 and holds 55% in this. Its partners are Chevron (30%) and NNPC (15%).