Equatorial Guinea: developing high-margin LNG
The country's rapid emergence as a 400,000 b/d oil exporter will be crowned when it becomes the African continent's fourth substantial LNG exporter, in just over two years. But the country's offshore attractions are still tainted by alleged government corruption and mismanagement of oil wealth, Martin Quinlan writes
Exports of liquefied natural gas (LNG) are on target to start in late-2007 from a $1.4bn venture that will be "one of the highest-margin liquefied natural gas (LNG) operations in the Atlantic basin", according to Marathon Oil, the firm implementing the project. The company estimates that operating, capital and feedstock costs will total "$1/m Btu at the loading flange" of the plant. Marathon has contracted to sell 3.4m tonnes a year (t/y) of LNG, but capacity of the plant will be in excess of this.
The facility is being built – by Bechtel – at Punta Europa, on the northwest side of Bioko island and close to the country's capital, Malabo. The construction cost will be about $1.0bn, equivalent to around "$260/t of installed capacity", says Marathon. The company indicated last month that production capacity will be about 3.8m t/y, supporting the cost figure. The additional $400m of costs covers project management, contingency, working capital, taxes, training, operations set-up and insurance.
The project is owned by Equatorial Guinea LNG, a venture between Marathon (75%) and state-owned Compañía Nacional de Petroleos de Guinea Ecuatorial (GEPetrol) (25%) – which is funding its share of costs through "the dedication of revenues from oil production", Marathon says. Marathon is funding its investment from its own resources, without loans. The firm says it is seeking to bring in other equity participants to reduce its own share in the venture and earlier this year quantified its target as selling a 13-15% interest out of its holding.
Considering a second train
However, the firm is also looking ahead to the construction of a second train at Punta Europa. "There is a great deal of gas in a small area around Bioko island and we see potential to develop a gas hub for the area," says a spokesman.
The buyer of the 3.4m t/y, for the first 17 years of the plant's operation, will be BG Gas Marketing. The firm will lift the LNG from the complex on a free-on-board (fob) basis, at prices linked mainly to the US's Henry Hub index. BG says the main destination for the LNG will be the Lake Charles, Louisiana, terminal in the US, but the fob agreement gives it the flexibility to take advantage of favourable conditions in other markets.
The source of the gas will be the Alba gas and condensate field, 25 km off Bioko's northwestern coast in 76 metres of water. Alba was discovered in the mid-1980s and was brought on stream as a minor condensate field, with a production of about 3,000 barrels a day (b/d), in 1991. After several changes of ownership, Marathon became the field's operator in early 2002 and subsequently increased its holding to 63.3%; its partners are Noble (33.7%) and GEPetrol (3.0%).
Alba is now known to be a large field, with remaining recoverable gas reserves estimated by Marathon at 125bn cubic metres (cm) – of which about 85bn cm will be needed for the contract with BG. Recent drilling on the Alba block seems likely to have added to the area's total. At the end of last year, a well on the Gardenia structure, 18 km southwest of Alba and in 98 metres of water, gave high flows of gas and condensate.
Finds near Alba
In June last year, gas and condensate were tested from the Deep Luba structure, which underlies the Alba field, with a well drilled from the Alba platform. Marathon is considering developing both discoveries through Alba's facilities. The firm also has finds in nearby blocks, notably the Bococo dry-gas discovery of July 2003.
Alba's gas and liquids are already being exploited. Under the operatorship of CMS (before Marathon) a 20 inch pipeline was constructed to land the gas near Malabo, where methanol and liquefied petroleum gas (LPG) plants were built. The Atlantic Methanol facility – now owned by Marathon (45%), Noble (45%) and state-owned Guinea Ecuatorial Oil and Gas Marketing (Geogam) (10%) – produces 2,500 t/d from 3.4m cm/d of lean gas. The LPG plant – Marathon (52.2%), Noble (27.8%) and Geogam (20%) – produces 2,700 b/d.
Marathon has implemented two expansion projects for Alba's liquids. Phase 2A, completed, increased condensate production and lifted total liquids output to 59,000 b/d, while Phase 2B – said last month to be mechanically complete – will raise LPG production to 16,000 b/d and will provide additional condensate capacity, giving a total liquids production of 79,000 b/d. Gas surplus to the needs of the methanol plant is sent back offshore for reinjection.
The country's largest producing field is ExxonMobil's Zafiro, lying about 70 km west of Malabo, but in much deeper water than Alba – the steeply sloping seabed gives water-depths in the area of 120-855 metres. Zafiro, together with a number of satellites, flows 300,000 b/d of light, low-sulphur crude (29.5°API, 0.26% sulphur).
Possibly because of its location, adjacent to the formerly disputed border with Nigerian waters, Zafiro was developed in a series of fast-track projects. The main field started flowing in August 1996 – less than 18 months from discovery – through the Zafiro Producer floating production, storage and offloading (FPSO) vessel, at 40,000 b/d for the first year then at 80,000 b/d when facilities had been enhanced. The FPSO's capacity was later expanded again and a fixed platform was installed in 168 metres of water to produce the Jade and Opalo satellites.
In July 2003, a third production facility was brought on stream – an early production system based on the Serpentina FPSO, moored in 476 metres of water. This taps the Southern Expansion Area, adding 110,000 b/d and taking combined output from the development to 300,000 b/d. ExxonMobil says that from the second quarter of this year all production will be blended and loaded only from the Serpentina.
The supermajor says recoverable reserves in Zafiro exceed 400m barrels, but other estimates for the wider area rise to 1.2bn barrels. Drilling continues, including – following an agreement with Nigeria – in the area up to the border. Interests are ExxonMobil, 71.25%, Devon, 23.75%, and the government, 5%.
While Zafiro has been expanding, the field that first pointed to Equatorial Guinea's larger oil potential – Ceiba, discovered in 1999 by Triton and now operated by Amerada Hess following its acquisition of that firm – has been a disappointment. The field is a low-energy structure and initial hopes for its production and reserves have not been met.
Ceiba was the first discovery in a new oil province – offshore Rio Muni, the African mainland part of Equatorial Guinea. The field, 35 km off the coast and in water 670-800 metres deep, was brought on stream through an FPSO-based early production system in November 2000. It flowed up to 50,000 b/d and there were hopes that the rate would double when, in January 2002, the FPSO was replaced by another – the Sendje Ceiba, with a processing capacity of 160,000 b/d. However, production did not increase. Amerada Hess said last month that Ceiba is flowing 40,000 b/d, but the firm added that the field is "performing as expected and we are very pleased with it".
Oil-in-place reserves are estimated at 0.7bn barrels, Amerada Hess says. A recovery factor of 30%, which the firm considers conservative, indicates recoverable reserves of 210m barrels – of which Amerada Hess has booked 150m barrels. "We will book additional reserves this year," a spokesman said, commenting on good results from the field's waterflood operation. Ceiba lies in Block G, where interests are Amerada Hess, 85%, and Tullow, 15% – although GEPetrol has a carried 5% interest in developments.
Amerada Hess is not planning further exploration in the area, but is concentrating on the development of its other discoveries in the block. In August, the firm launched the Northern Block G (NBG) development, under which the Okumé, Oveng, Ebano and Elon fields will be brought on stream in the first quarter of 2007. Production is due to build up to a plateau of 60,000 b/d in that year, achieved at a project-lifetime cost of $1.1bn – a relatively high figure for which the area's complicated geology takes the blame.
Because of the reservoir complications, which include stacked producing intervals, the firm anticipates the need for well interventions throughout the life of the fields. Accordingly, the NBG development rejects the usual – for the deep-water Gulf of Guinea – subsea-to-FPSO approach, in favour of multiple platforms with surface wellheads.
Two platforms, at water-depths of 274 metres and 534 metres, will be tension-leg platforms (TLPs) – a decision which doubles the Gulf of Guinea's population of TLPs, the other two being at Angola's Kizomba A and B developments. The TLPs will tap the Okumé, Oveng and Ebano fields. There will be four other platforms, all fixed structures in 46-70 metres of water – three wellhead platforms over the Elon field and a central processing facility, also over Elon. Oil will be piped 24 km to the Sendje Ceiba's 2.1m barrels of storage capacity. In total, there will be 29 producing wells together with 16 water-injectors and two gas-injectors.
Amerada Hess has made several other discoveries in the area, with tie-in possibilities. Particularly promising is the firm's November discovery with the G-19 well, drilled less than 2 km from the NBG fields. The well, in 385 metres of water, found over 34 metres of net oil zone.