West African Deep Water

[Published in issue No 98, October 2000 of The Hydrographic Journal ]

Development Prospects in a Global Context

Dominic Harbinson
Douglas-Westwood Limited, Canterbury, England.

Dr Roger Knight
Infield Systems, London, England.

John Westwood
Douglas-Westwood Limited, Canterbury, England.


At the end of 1999 there were 233 offshore oil and gas fields in production in the West African region between Angola and the Ivory Coast (Côte d'Ivoire). These fields currently produce some 3.1 million barrels of liquids per day. The region thus bears itself well in comparison with other shallow water areas of the world such as the North Sea and South East Asia. But it is the immense promise of the giant deepwater 'elephant' fields that is fuelling the current boom in exploration and development in the region and raising the levels of investment coming into it.


From its start in the early 1960s offshore West African exploration was crowned with success in the shallow waters off the Niger Delta, off the Port Gentil region of Gabon and with the discovery of the Emeraude field off the Congo. Development soon followed and the Okan field in Nigerian waters started up on 21st March 1965. Since then, through to the end of the year 1999, 233 fields have come into production, utilising the services of seven hundred platforms, to produce up to 3.1 mm bbl/d (barrels per day) of liquids from some 24.63 billion boe (barrels of oil equivalent) accessible reserves.

Fig. 1: Global Deepwater Reserves (prospects under consideration)

The Geological Background

It is now seventy years since the German scientist Alfred Wegener proposed the idea that the geographic fit of the western coast of Africa and the eastern coast of South America pointed to the fact that the two continents had once been joined together in the geological past. When that had been was a matter of some debate until advances in marine geology over the next forty years led to the recognition that the two continents had separated at the end of the Jurassic and the very beginning of the Cretaceous periods by a process of rifting and oceanic suturing that split the super continent of Gondwanaland into several pieces.

As the split between the continental landmasses developed from the Late Jurassic into the Early Cretaceous periods contemporaneous pre- and syn-rift deposits were laid down on both sides of the South Atlantic. Thus were produced two very similar hydrocarbon provinces with regard to basin type, source rocks and salt deposits. The salt deposits were laid down in a region of poorly circulating waters lying north of the volcanic rocks that now constitute the Walvis Ridge in the eastern South Atlantic and the Rio Grande Rise in the west, (Fainstein, 1998). The location of these two volcanic ridges still effectively delineate the southern margins of the hydrocarbon bearing Lower Congo and Santos/Campos basins to the north. However, more southerly basins, for example, off Namibia and the Falklands/Malvinas Islands do occur, and will certainly be of more future exploration interest.

Following the period of evaporite deposition in the Albian and Aptian, further rifting led to the opening up of the South Atlantic and the deposition of a series of post-Aptian clastic post-rift sediments as the marginal shelves subsided. The salt deposits are of particular importance because of the effect they have on the post depositional sediments that blanketed them as the ocean opened and a massive basinward sediment influx of turbidites and other closely related Tertiary clastic deposits occurred. These fan deposits, turbidites, particularly those of Oligocene and Miocene age, now form the bulk of the reservoir rocks in the deepwater fields that have been found in the Congo Basin. These sediments lie off the continental shelf, below the continental slope, and finds have been made in them in water depths of between 300 and 1,893 metres. The recognition of the importance of these deep sea fan deposits over the shallow water progradational shelf deposits in which earlier offshore finds were made is one of the most important discoveries to come out of deepwater exploration, both off Brazil and in the deeper Gulf of Mexico as well as off West Africa.

Recent seismic survey work in the Angolan portion of the Lower Congo Basin and in the Campos Basin has shown that post-depositional salt movements have created various trap types in the overlying sediments. The salt thickens towards the African shore and has produced different structures in the extensional tectonic environment that lies in the upper margins of the basin from those that occur in the area affected by compressional tectonics in the western and deeper parts of the basin, (Keaveny, 1998).

The History of Deep Water Exploration and its Results

The first giant deepwater fields of economic importance to be found in West African waters were Bonga in Nigerian Block OPL 212 and Girassol in Block 17 off Angola in the Spring of 1996. Since then a total of 43 further fields have been discovered in water depths ranging from 300 metres to 1893 metres and the region has risen to be the world's hot-spot in terms of new reserves found. Deepwater reserves currently represent about 25% of the world's total offshore reserves awaiting development in the time frame 2000 - 2010 (Tables 1, 2 and 3).

At the present moment only two deepwater West African developments are actually on stream. The first was the Topacio HOST template tied back to the then Mobil Oil Company's Zafiro FPSO on the northwestern edge of Equatorial Guinea's Block B right up against the median line with Nigerian blocks OML 102 and OPL 223, and the second, and most recent is phase 1 of Chevron's Kuito development in Angola Block 14 which came on stream in December 1999.

Map 1: West African Regions



Liquids (MMBBL)

Gas (BCF)

Asia Pacific 1,486 25,010
Brazil 5,143 2,307
Gulf of Mexico 5,016 11,395
Norway 1,976 32,622
UK 365 6,000
West Africa 13,330 17,870
Other 525 119,396
Total 27,315 214,601

source:- Infield Database, London

Table 1: Deepwater Fields on stream 2000 - 2010 (Water Depth 300m +)



Liquids (MMBBL)

Gas (BCF)

Asia Pacific 9,562 259,708
Brazil 505 1,478
Gulf of Mexico 174 4,324
Norway 2,893 15,324
Other 41,381 602,912
UK 3,891 22,070
West Africa 4,152 13,891
Total 58,406 905,817

source:- Infield Database, London

Table 2: Shallow Water Fields on stream 2000 - 2010 (Water Depth <300m)


Shallow Water

Asia Pacific 786.20 7,379.04
Brazil 739.99 102.17
Gulf of Mexico 936.95 124.81
Norway 1,030.20 745.89
Other 2,876.56 19,688.90
UK 189.70 1,037.64
West Africa 2,197.22 879.35
Total 8,756.81 29,957.78

source:- Infield Database, London

Table 3: Deepwater vs Shallow Water Reserves (MTOE) 2000 - 2010

The Lower Congo Basin - Angola and Congo (B)

The most important area by far is north and south of the mouth of the River Congo. Off Angola, twenty five fields have been found in the last four years with reserves currently estimated to be in the region of 9 billion boe of which two-thirds is oil (Table 4). This is just as well, because there is really no infrastructure in place for dealing with large volumes of associated gas at present. The finds to date have been made in Tertiary reservoirs in Blocks 14, 15, 17 and 18 operated respectively by Chevron, ExxonMobil, TotalFinaElf and BP Amoco.


Shallow Water


Nos Fields


Nos Fields






Angola 24 1,099 63 168
Cameroon 0   30 101
Congo 3 123 21 49
Equatorial Guinea 1 55 3 9
Gabon 0   33 37
Ghana 0   3 25
Ivory Coast 0   5 26
Nigeria 12 920 112 463
Total 40 2,197 270 879

source:- Infield Database, London

Table 4: West African Fields On Stream 2000 - 2010

North of the Cabinda enclave, in the narrow Haute Mer zone of the Republic of the Congo, TotalFinaElf has a series of what appear to be three smaller finds than those made in Angolan waters, but their proximity to the border may lead in time to the discovery that they do in fact extend into Angolan waters or vice-versa. The three finds - Moho, Bilondo and Libonolo - which are located in WDs 546-800m, hold combined reserves estimated at 925 mmbbl. The French operator has yet to decide whether their development as subsea tiebacks to N'Kossa is preferable to the stand-alone floating production option. Meanwhile, further important Tertiary discoveries are still being made.

This year drilling has begun in the deeper waters off the northern mouth of the Congo River where four huge blocks, the Mer Profonde Nord (ExxonMobil), the Mer Profonde Sud and Mer Tres Profonde Sud (TotalFinaElf), and Mer Tres Profonde Nord (Agip) have been permitted. Although the Muhanga Marine-1 well in the Mer Profonde South was unsuccessful, the Andromede Marine-1 well drilled by the Stena Tay semisub came up trumps in the Mer Tres Profonde Sud permit. The well was drilled in WD 1,893 m - making it the deepest to date off Congo - and tested at 7,000 b/d of high grade oil. However, given the tremendous success which TotalFinaElf has enjoyed in West African waters, this highly promising discovery may have to wait in line pending the development of the operator's other large finds off Nigeria and Angola (Hart's Africa Oil & Gas, 1 June, 2000).

A View to the North, Gabon and Equatorial Guinea

Immediately north of the Congo acreage, in south-east Gabon ultra deepwater >2,000 msw comes closer inshore than to the south. Here TotalFinaElf (28%), Unocal (25%), Kerr McGee (14%) and RB Falcon (11%) have all bought into Vanco's (22% now) holdings of the Anton and Astrid Marin permits of 6,600 and 6,000 square kilometres respectively. Water depths range from 1,000 to 3,000 metres and 20-32 prospects have been identified with a potential as great as that of the Angolan blocks. A further nine deepwater blocks are to be offered in Gabon's ninth licensing round.

Another very interesting deepwater area is on the border between Nigeria and Equatorial Guinea, where the Zafiro field and its associated satellites show good promise for a developing play exploration programme. On the strength of their activities in Equatorial Guinea, the then Mobil Oil was given exclusive rights to explore and technically evaluate 22 blocks in the neighbouring deep waters of Sao Tome and Principe for eighteen months, (Oil & Gas Journal, Vol. 96, No 40, 1998, p.112). However it was Triton Energy, now working with Energy Africa, that made a major break through in 1999 with the discovery of the La Ceiba field in Block G. This is currently being fast-tracked as a four well subsea early production system tied into the 275,000 dwt Berge Charlotte presently being upgraded in Singapore for completion by year end. A much larger twenty well scheme could come in a year or two.

About fifteen miles to the southwest, frontier specialist Vanco has signed up for the Corisco Deep block (Block K) covering 1.1 million acres and extending into water depths of 2,500 metres, (Energy Day, April 7, 2000, p.6), on what is hoped to be an extension of La Ceiba's geological trend. Vanco is planning 2,000 km² of 3D seismic in 2000 with a first wildcat expected within 2 years. Meanwhile Chevron has taken up operatorship of Block L which lies to the west and north of Triton's acreage and is also believed to be on a trend with La Ceiba. Chevron meanwhile has picked up Block L which is also on trend with La Ceiba. The oil major's work programme includes seismic acquisition and exploration drilling requiring an estimated spend of $15-20 million (Petzet, 2000).

Nigeria - a Late Starter but Coming on Strong

To the north the pickings were viewed as less certain (Knight and Westwood, 1999), but deepwater drilling off Nigeria has since been very successful. At that time for instance, apart from Shell's Bonga field, no other really large and worthwhile finds had been made, and none that would have been worth developing under the extremely tight financial conditions pertaining in early 1999. In complete contrast in the year 2000 with an oil price above $20 a barrel and price stability envisioned in the medium term the situation looks entirely different. The majors are spoilt for choice. In block OPL 209 ExxonMobil has good discoveries at Bosi and most recently and importantly at Erha and in the neighbouring blocks of OPL 216, 217 and 218 Texaco/Famfa and Statoil have made the very significant Agbami and Nnwa discoveries.

These two major finds, Erha and Agbami, also illustrate two other problems the industry faces at the moment: the skills shortage and the cash shortage. The period of low oil prices and consequent mergers in the oil industry in the last two years have played havoc with the organised and planned development of company strategies. All too often decision-making criteria have been dominated by short-term concerns about share prices which have obscured any clear-sighted appraisal of longer term objectives. Many skilled employees have been shed in post-merger efforts to achieve economies of scale. As a result of this downsizing, many companies are not able to respond to all the challenges that they face at the moment, as they would like. In the case of ExxonMobil the full development of Erha will probably have to follow on that of the Kizombo project in Angola Block 15 because there is just not enough slack in the system to accommodate the development of two such projects concurrently without a fair degree of synergy between them.

In the case of Texaco, it is faced with choices for its funds: Agbami, the company's largest find in forty years and Frade off Brazil to the north of the giant Albacora field. These are in reverse order of discovery, but priority order for development funds. Unfortunately the low oil price, coupled with the flight of capital into the investment dot.com companies, has left many companies with hard choices to make when it comes to selecting which fields in their portfolios to develop.

The Remaining Players, Ghana and the Ivory Coast

Deepwater blocks have been licensed off both Ghana and the Ivory Coast covering prospects in Cretaceous - Tertiary sedimentary environments not exactly the same as those found to the south and east, (Cameron and White, 1999). Real prospects they are, but prospects they still remain as no conclusive discoveries have yet been made. Ocean and Shell drilled in block CI-105 in the midst of the Ivorian coastal blocks, but drew a blank. Likewise Hunt in Ghana's Cape Three Points WCTP-2X found only oil shows. Most recently, however, Dana's West Tano WT-1X, drilled right on the edge of the continental shelf, has found oil in two levels of Cretaceous sands, indicating a much more positive result. Different geological modelling will be necessary to understand this area however, before all its secrets are revealed.

Overview - Operatorships

The overall situation is, therefore, very strong and very promising. TotalFinaElf and Chevron operate the blocks in which most of the reserves of the first development wave have been found, but as Table 6 clearly shows, equity holdings spread across the various fields by companies tell a different story. While TotalFinaElf still holds a very important position in West Africa other major players are also important, and in fact ExxonMobil overtakes them all on percentage of total reserves held across the whole of the region, on the strength of its recent successes in Nigeria.

Fig. 2: Field Holdings in Deepwater West Africa

Reserves (MTOE)

Share of Total (%)

ExxonMobil 488 20.9%
TotalFinaElf 398 17.0%
Shell 328 14.1%
BP Amoco 217 9.3%
Texaco / Famfa 164 7.0%
Agip 155 6.6%
Statoil 136 5.8%
Chevron 136 5.8%
Others 314 13.4%
West Africa 2,336 100.0%

source:- Infield Database, London

Table 6: Field Holdings in Deepwater West Africa

A Closer Look at the Current Angolan Developments

At the moment there is really only one development scenario being considered and that is floating production. This will come either in the form of a Dry Completion Unit (DCU), a SPAR or a Tension Leg Platform (TLP) in association with a Floating Production, Storage and Offloading vessel (FPSO), or a stand-alone FPSO with direct subsea tiebacks. Table 7 shows clearly the potential demand for subsea completions off West Africa compared to the existing situation. West Africa is very much the coming place for subsea work and Angola Blocks 14 to 17 will lie at its heart.

In Block 14, Chevron is currently at work on the next phase of the development of the Kuito field in 400 m water depth. This will involve tying back 8 subsea completed water injection wells to the FPSO. Gas is also being injected as the intention is to flare no gas. After a period of production a decision will be made as to whether to go for a second phase of development in two to four years time. Other fields in this block are Kuito South, Benguela, Landana and the most recent find Belize, which may be viable as another stand alone development or as subsea tiebacks to an expanded Kuito scheme.

Projects On Stream

Prior 2000

Projects On Stream

2000 - 2010


Nos Wells


Nos Wells



Depth (M)


Depth (M)

Angola 16 246 324 1,086
Congo 7 95 51 547
Equatorial Guinea 20 230 31 684
Gabon 1 41 3 76
Ghana     2 100
Nigeria 1 26 141 1,136
Total 45 182 552 1,026

source:- Infield Systems, London

Table 7: West African Subsea Completions

ExxonMobil operates Block 15 to the south. Here, seven fields (Hungo, Chocalho, Kissanje, Marimba, Dikanza, Xikomba and the just announced Mondo) containing around 2 billion boe could be developed together in an integrated scheme. This is to be based initially on the Hungo - Chocalho area with a DCU - a SPAR - tied back to an FPSO. The other finds will subsequently be targeted through a series of subsea tiebacks and a second DCU.

Block 16, formerly operated by Shell, but now relinquished, is the poor relation at the moment. The Bengo and Longa finds have not been reported as commercial on a stand alone basis. However as exploration was at a very early stage, further success may be anticipated when a new consortium led by Texaco takes over the acreage. From Petrobras's experience in the Brazilian Campos Basin, turbidite reservoirs, in which most of the most prolific Angolan deep water finds have been made, pay better on further exploration, (Pettingill, 1998).

The largest development at present is that of TotalFinaElf's Girassol B Oligocene reservoir where some forty subsea wells, including some 23 production wells, 14 water injection wells and 3 gas injection wells are going to be tied back to the world's largest FPSO, whose hull is currently under construction in South Korea, by three novel riser towers, (Euroil, October 1998, p.31). The function of these towers is to insure that the wellhead fluids rise smoothly and continuously from the seabed through the cold sea water to the production modules with the minimum of wax and hydrate formation blocking the pipes. Adjacent to the field is the Girassol C reservoir that may be tied back at a later date and the nearby Dahlia 1 and Dahlia 2/Camelia fields as well as the Rosa/Orquidea/Jasmin and Lirio/Cravo fields which will probably need separate production facilities for their full development in due course.

The southern blocks of Angola 18 to 30 and the ultra deepwater blocks 31 to 34 look particularly prospective because of their potential to mirror Brazil's Campos Basin on the other side of the oceanic divide, where the giant Albacora, Marlim, Marlim Sul and Roncador fields all occur in similar reservoir rocks and tectonic environments, (Schenk, 1999). Exploration has already begun in the BP Amoco operated Block 18 and three finds have already been made. Our conclusion is that not all of the cherries have been picked offshore Angola by any means. Deepwater exploration began in Brazil a decade before it started off West Africa, but it was not until twelve years later that the super giant Roncador field, with reserves of nearly 3 billion boe, was discovered. This is not to say that we can predict where and when huge discoveries are likely to be made, but we would be surprised if during the next five years or so further new and substantial discoveries are not made.

The flaring of produced gas is common practice throughout the West African region and Angola is no exception here. In a region where electricity supplies are woefully inadequate and where much deforestation is driven by the demand for cooking fuel, this profligacy has understandably provoked much criticism. Currently 85% of Angolan gas production is flared although the government is now discouraging this practice and seeking to promote its profitable utilisation. Obstacles to this worthy aim include a lack of infrastructure, undeveloped local and regional markets, heavy investment requirements and continuing perceptions of political risk. Despite these features, a number of schemes have been mooted. Current ideas include a $2.5 billion liquid natural gas plant proposed by Texaco which would take in gas from offshore acreage including deepwater Blocks 15, 17 and 18, and a gas to liquids plant producing fuels such as diesel and naphtha which Chevron and the South African company Sasol are proposing. Neither scheme seems likely to progress from the drawing board in the near future however, so reinjection is probably going to be the most expedient option to reduce flaring.

An Analysis of the Many Prospects

Fig. 3: Capital expenditure forecasts

source: The World Deepwater Report

West Africa offers the most exciting prospects of all of the world's deep water hydrocarbons plays. Work on The World Deepwater Report 2 indicated that over the period to 2004, about $17 billion of capital expenditure will be invested there. This is a similar figure to Brazil, the Gulf of Mexico and Europe. However, Europe is a high cost province due to its harsh operating environment.

Fig. 4: Comparison of average deepwater field reserves

source: The World Deepwater Report

The Gulf of Mexico is highly explored and dominated by a series of small prospects - any major growth awaits decisions on the future use of FPSOs. Brazil currently dominates today's deep water activity and Petrobras has recently announced expenditure of $8bn over the next four years - but it is by comparison a more highly developed deepwater domain. West Africa only has two deepwater fields producing, but a growing list of major finds undergoing and awaiting development.

To give one other comparison, The World Deepwater Report 2 considered the fields likely to be developed on a stand-alone basis. In the Gulf of Mexico the average reserve size was 80 mm bbl, in West Africa 500 mm bbl. The great West Africa elephant hunt has bagged some major trophies, but there are many more prizes in prospect.

Note: The data of future prospects discussed above relates to fields under consideration for development. Unless stated otherwise this is not a forecast of future activity.

Data sources

The World Deepwater Report 2 (www.dw-1.com) provides an overview of global activity and forecasts the deepwater market over the period 2000-2004.

The Offshore West Africa Report (www.dw-1.com) gives an overview of activity and business prospects for the region over the next five years.

Infield Systems database (www.infield.com) contains details of existing and proposed global offshore field developments.

DeepWater Online (www.deepwater.co.uk ) is a new service. It provides detailed information on existing and proposed field developments in water depths of 300m or greater.


Cameron, N.R., and White, K., Exploration Opportunities in Offshore Deepwater Africa, IBC 'Oil and Gas Developments in West Africa' conference, London 25-26 October, 1999.

Esau, I., Andromede boost for Congo, Energy Day, April 7, 2000, p.6.

Fainstein, R., and Gregory-Sloan, J., South Atlantic Salt Basins : The deepwater challenge, Brasil Energy, No 316, 1998, pp. 8 - 10.

Development doubts cloud W Africa finds Hart's Africa Oil and Gas 1 June, 2000; p.1

Keaveny, M., Hydrocarbon prospectivity, salt tectonics offshore Angola, Offshore Magazine, October, 1998 pp. 68, 70 and 170.

Knight, R.M., and Westwood, J., Long-term prospects very bright for deep waters off West Africa, Oil & Gas Journal, Vol. 97, No. 3, 1999, pp. 33 - 38.

Pettingill, H.S., World Turbidites - 1, Turbidite plays' immaturity means big potential remains, Oil & Gas Journal, Vol. 96, No. 40, 1998, pp. 106 - 112.

Pettingill, H.S., World Turbidites - 2, Lessons learned from 43 turbidite giant fields, Oil & Gas Journal, Vol 96, No 41, 1998, pp. 93 - 95.

Petzet, A. Equatorial Guinea's offshore attracts more operators as Gulf of Guinea action intensifies, Oil & Gas Journal May 29, 2000; pp 43-44.

Poruban, S., Salomon: 2000 E&P spending outlook bullish, Oil & Gas Journal, Vol 98, No 15, 2000, pp. 50 - 52.

Rising to the top, Euroil, October 1998, p. 31.

Sao Tome acreage boosts Mobil off West Africa, Oil & Gas Journal, Vol. 96, No. 40, 1998, p. 112.

Schenk, C.J., Assessment of oil/gas resources in the Campos Basin's Lagoa Feia system, Offshore Magazine, October 1999, p. 60.