WEST AFRICA Operators gather for deepwater probes of Africa's Atlantic margins

Five river deltas main attraction, but key features
of continental separation may provide long-sought production

The Qua Iboe Channel lies in the southeastern quadrant of the Niger Delta's structural elements. [53982 bytes]
A schematic geological cross-section across the Aptian Salt Basin, offshore Congo. [49185 bytes]

Like swimmers in a race, countries along the west coast of Africa are taking a simultaneous plunge into deepwater exploration. The 1990s are witnessing a heightened, regional interest in the marine frontier, on the continental slope of the Atlantic, which has been largely unexplored since the first well was abandoned dry 21 years ago.

Much of the initiative is coming from governments, who are opening up new areas and dismantling barriers in the way of foreign investment. But the exploration activity is driven by the major operating companies, some of whom are either entering Africa anew or staging a comeback.

Except for Namibia, deepwater activity has been higher in countries that have established some measure of prolificity in shallower water and land leases. Several billion dollars are being spent on short term work programs in deepwater tracts where the petroleum geology is relatively unknown. And here's the challenge: the operators are relying on vastly improved technology, including high resolution 3D seismic-based sequence stratigraphy and multidisciplinary approaches to basin analysis, which have fared them well in deepwater terrains elsewhere in the world.

The campaign has seen starkly impoverished countries turn into putative oil producers almost overnight. And small independent companies suddenly are becoming big players.

Arco's production sharing contract for the Otiti Block offshore northwest Gabon, which was signed last August, is the latest in a spate of new investments in West Africa's deepwater area. It is Arco's first upstream venture in Gabon. The company proposes to acquire 3D seismic data later in the year and perhaps drill a well next year.

Exxon's first acreage in Congo, announced last May, is Marine Profound, geologically situated in the distal part of the Coastal Basin, a part of the Aptian Salt. It covers 1.8 million acres and is some 80-120 km offshore in water depths between 200 meters and 2,000 meters.

Southeast, 700 km from Arco's new lease, in offshore Congo, Elf is promoting the development of the 400 million bbl N'Kossa Field, located in 170-300 meters water depth, which may become the first African deepwater oilfield to come onstream. Elf holds 51% in the group that has bought into N'Kossa - which is in the Haute Permit block - and to finance its own share has arranged borrowing of $1.7 billion from eight international banks.

South of the Elf-operated Haute Permit, which incorporates N'Kossa, four blocks (14, 15, 16, and 17) lie on top of one another at between 200 meters and 1,500 meters water depth offshore Cabinda. Last year, a Chevron-led group was awarded Block 14 (70 km off Cabinda), the northernmost of these blocks. Exxon holds Block 15, Shell is operating Block 16, and Elf has Block 17. Mobil will likely get Block 20, located in about 600 meters of water. Amoco is rooting for Block 18.

In Nigeria, 15 of the 21 deepwater blocks have been under license since 1993, the most active player being the BP/Statoil alliance, which operates three leases and is the active partner in a fourth lease in which it has 40% equity. But among the major financial investors are Amoco (which doesn't operate any lease) and Exxon, (which holds only one). Exxon affiliates have interest in seven of the 15 licensed blocks. Amoco is investing about $100 million in three blocks. And Conoco, here for the first time, is operating two leases.

Mixed results

Angola, Equatorial Guinea, and Namibia have witnessed the busiest drilling activity since the current campaign began. Chevron's first deepwater well in Block 14 offshore Angola may be spudded early next year, but so far Elf has reported gas and condensate in deepwater wildcat Magarida-1 (Block 17) in 1000 meters of water. In Block 16, Shell has drilled two wells on the Bengo structure (well #1 tested 1,780 b/d oil) and another wildcat, Cunene-1, elsewhere on the same block in 480 meters of water.

The big surprise has been Equatorial Guinea, which wasn't even expected to witness any drilling activity this year. In March, a Mobil/United Meridien (65:35) joint venture discovered the Zafiro oilfield in 200 meters water depth offshore Equatorial Guinea. The discovery well Zafiro-1 tested at rates exceeding 10,500 b/d oil and 3.4 MMcf/d gas in the Qua Iboe. Well #2 found the oil-bearing sand in Zafiro-1 to be thinner, but it encountered a new deeper oil reservoir and was cased for future production. Zafiro-3 tested 10,237 b/d oil in the same formation and extended the accumulation approximately 2.5 km southwest of the discovery well.

Meanwhile, a new well, Opalo-1, drilled about three km northeast of Zafiro-1, tested a combined 7,818 b/d oil from two sands, both reportedly new pay zones, in a pre-Qua Iboe.

Mobil has since commenced acquisition of 1,100 sq km of 3D seismic over a large portion of the Block B lease, in order to aid further development plans for Zafiro, as well as to delineate exploration prospects on trend.

The Zafiro find promises to elevate the status of Equatorial Guinea from a potential modest gas and condensate producer to an oil-producing nation. Already, it has bolstered the image and confidence of United Meridian, the small independent company that is Mobil's partner in the project. Since the finding UMC has signed for a new offshore PSC agreement for Block D, and 808.5 sq km acreage located east of Block B. UMC (100%) is offering up to 50% to interested parties. The obligations call for the acquisition of 250 km of new seismic during the first two-year period.

Things have been much calmer in the deepwater tracts offshore Nigeria, despite the fact that most of the leases have been licensed for as long as 30 months.

The entire Nigerian oil industry is keenly watching the slow progress of Oyo-1, spudded last July by a domestic company, Allied Petroleum, in 316 meters water in OPL 210. BP-Statoil is the technical partner.

In Namibia, the Norwegian company, Norsk Hydro drilled a dry hole in 491 meters of water in 1993. This year, they have drilled another, which was suspended with undisclosed results. Ranger Oil plugged the 2213/6-1 well, located in 218 meters water in the Southern Walvis Bay Basin after drilling to 2,605 meters in rocks of Mesozoic age.

Sasol foraged into 680 meters water depth and was still drilling at the time of this report. But there is hope for some find in this newly independent country. Ranger is committed to a second exploratory well in a couple of months. Norsk hopes to spud another wildcat in mid-1996, and Chevron will drill its first well any time from now.

Deep petroleum geology

Much interpretation work is required to be done to get more than a hang of the deepwater geology of the Atlantic coast of West Africa.

But the area is essentially the far downdip outreach of each of five identifiable basins stretching from Cte d'Ivoire to Angola. Given the nature of the earth sciences, it is not an accident that the major finds so far have been the deepwater extensions of well known plays in the shallower offshore. Congo's N'Kossa Field is situated in 170-350 meters water depth in the Aptian Salt Basin (a marginal sag basin extending from Gabon to Angola), whose petroleum habitat has been rigorously articulated from well data studied updip. The oil sands of Equatorial Guinea's Zafiro belong to the Qua Iboe which is well documented from wells in shallower offshore Niger Delta.

The N'Kossa Field was discovered in 1983, almost a decade before the current, massive Africa-wide deepwater campaign. The oil is trapped in the sandy and carbonate reservoirs of the Senji Formation - of Albian age - estimated to hold a total oil and gas column up to 400 meters with producible reserves estimated at about 400 million bbl.

Integration of 3D seismic data with the four wells drilled so far, depict the structural geometry as a complex turtle-shaped feature extending over 30 sq km. (Vernet, AAPG, 1995). Regionally, the N'Kossa structure is surrounded by large Upper Albian to Cenomanian depositional troughs and minor Aptian residual ridges. The field had been identified as far back as 20 years ago on seismic data of mid-1970s vintage. And then in spite of its promise, the N'Kossa-1 discovery was considered as sub-commercial because of the water depth. Subsequent re-evaluation as well as 2D and 3D seismic and three delineation wells, confirmed the presence of major oil reserves and led to the present development.

The turtle-shaped structure which describes the N'Kossa Field is typical of the structure of reservoirs in the Congo affiliate of the Aptian Salt Basin, even when they are not in deepwater. This structure is linked to salt tectonics.

The basin is characterized by a Jurassic to Lower Cretaceous, non-marine rift sequence followed by a transgressive sheet sand before the deposition of the Aptian salt. Although numerous evaporite cycles occur in the south above the salt, generally the Albian is characterized by a marine carbonate platform. (In the N'Kossa Field, this marine carbonate platform is absent. This suggests an early formation of the structure and explains why it is draped by sealing shales.)

The overlying, Upper Cretaceous to Tertiary sequence in the basin is mostly clastic, except for a few minor carbonate cycles. Source rocks are chiefly the pre-salt, non-marine lacustrine shales with minor sources in basinal shales coeval with the marine sandstones.

In Gabon, many of the reservoirs in this basin are pre-salt fluviatile and turbidite (lacustrine) sands. When it fits into the right architecture, the transgressive sheet sand is an excellent oil-bearing sand. It also serves as a migratory pathway. But in Congo, 99% are proven hydrocarbon reservoirs in post salt sands.

In some cases, tilted fault blocks in the pre-salt interior fracture basin, and salt movements, stimulated by either fault reactivation or differential basin subsidence are the key structuring mechanisms in trap formation. In others, post salt oil deposits are dependent on a migratory pathway from the pre-salt source beds. One such mechanism is via listric faulting, accompanying salt tectonics, with faults soling out at the base salt detachment surface. In N'Kossa, local salt tectonics and possible regional raft tectonics are the proposed mechanism for structuring.

Zafiro Field, so far the major discovery of the 1990s Africa-wide deepwater campaign, is located about 36 km southeast of Mobil's Edop Field, which itself is located in the unique Southeastern petroleum system of the Niger Delta Basin.

Ordinarily, the stratigraphy of the Niger Delta Basin consists of a distinct delta top (Benin Formation), deposited in alluvial or non-marine sand; delta front (Agbada Formation), the hydrocarbon-prospective sequence, represented by an alternation of sands, silts, and clays in various proportions and thicknesses; and prodelta (Akata Formation) facies, composed of shales, clays, and silts, as well as a few streaks of sand.

However, in the southeastern offshore, the Agbada Formation (delta front) is further subdivided into Biafra, Rubble, and Qua Iboe members, which are manifestations of the paleo cross river delta, a sort of sub basin that developed on the eastern margin of the Niger Delta Basin. The Qua Iboe member is a clay-filled channel within - which are prospective sand packages. Four such intra-Qua Iboe reservoirs have been well documented and are excellent stratigraphic traps.

The oil-bearing sands in the Zafiro Field are one such intra-Qua Iboe reservoir structurally draped over Miocene thrust sheets. Previous workers have mapped the Qua Iboe member only as far as the limit of the Late Miocene-Pliocene delta, and in wells which are shallower than 160 meters of water (Doust & Omatsola, 1989). The Zafiro discovery suggests that the Qua Iboe reaches beyond the distal belt areas and as far as the depocenters of the continental slope in the present delta.

The intra-Qua Iboe sands were deposited on an upper slope in close proximity to the shelf edge. Through time, as the shelf edge migrated seaward, deposition began with a turbidite channel dominated slope system and progressed through a slump-debris flow dominated slope system to a tide and wave dominated, collapsed shelf-edge deltaic system. the key reservoir is the slump/debris flow dominated slope system. According to a Mobil paper, presented at the AAPG in 1995, seismic facies depict the intra-Quo Iboe as both sheet-like and mounded external forms (geometries) and parallel/continuous as well as chaotic/hummocky internal reflections, because of differences in stacking patterns of sandy and muddy slump interval. In wireline logs, slump facies exhibit blocky, coarsening up, and serrated motifs.

"In the absence of conventional core", the paper notes, slump facies may be misinterpreted and even miscorrelated because seismic facies and log motifs of slumps and debris flows tend to mimic properties of turbidite fan deposits. This is the description as observed in the Edop Field, and one must be careful to assume it to be entirely correlatable with the events in the Zafiro Field, 36 km southeast. In any case, it provides us with a rough but intelligible idea of the lithostratigraphy in Zafiro.

The slump-dominated reservoir facies of the Edop Field is composed of unconsolidated fine-grained sand. Thicknesses of individual units varies 1-34 ft, but amalgamated intervals reach a thickness of up to 70 ft and apparently form connected sand bodies. Porosity commonly ranges from 20% to 35%, whereas horizontal permeability ranges from 1000 md to 3,000 md.

The Aptian Salt and the Niger Delta Basins, to which N'Kossa and Zafiro respectively belong, are among the five basins along the West Coast. These basins are all part of a large linear trough which has been subsiding since the late Jurassic time when the super-continent Gondwanaland broke up into West Africa and South America, forming the Atlantic Ocean between them. The other three include:

The Abidjan Basin, extending from Cape Palmas Escarpment (St Paul Fracture Zone) in the west to Romanche Fracture Zone in Lome in the east. It straddles Cte d'Ivoire, Tano, Ghana, and Meta sub Basin in Ghana.
The Dahomey Basin, is structurally defined by the Romanche Fracture Zone in the west and the Okitipupa high in the east. Its maximum development is in offshore Benin Republic. The flanks extend to Togo in the West and Nigeria in the east. The basin is Cretaceous.
The Rio del Rey-Cameroon-Fernando Po Basin, which is the east offshore extension of the Niger Delta. It is bound in the east by the Cameroon-Annobon volcanic axis, which is part of the Fernando Po-Ascension Fracture Zone extending into the Atlantic.

The deepwater segments of these three basins have been much less explored, in part because the landward provinces have not yielded much.

Some oil has been found in the deepwater offshore the Abidjan Basin in Cte d'Ivoire by Phillips Petroleum, as far back as 15 years ago. But Cte d'Ivoire doesn't appear very deep to participate in the current race for prospects in deep water. After all, the results of exploration efforts in shallower water and landward parts of the basin have not been very encouraging.

The Cretaceous Benin Basin has yielded very little hydrocarbon, compared to its younger cousin, the tertiary Niger Delta to the east. Even in Nigeria, where there is a lot of enthusiasm for deepwater prospects, operators have generally shied away from the deep offshore Benin Basin. Out of the six remaining unlicensed blocks in the deep offshore Nigeria, four are in deep offshore Benin Basin.

It would take a couple of years more to determine the success or otherwise of the current deepwater efforts along the Atlantic coast of Africa. Zafiro, in 200 meters of water and N'Kossa, with water depths ranging from 170 meters to 350 meters, are in relatively shallow water depths than most deepwater wells already drilled in these parts, as well as the prospects being proposed. Their proximity to the shelf explains in large part why they are stratigraphically correlatable with fields updip. These two fields are exceptions to the challenges faced by operators in search of deepwater treasures.

A key risk to prospectivity of the deepwater offshore Angola, Nigeria, Equatorial Guinea, and Congo is the presence of reservoir sands. Another problem, especially in deepwater offshore Nigeria, is interpretation of structural timing as it relates to hydrocarbon migration. These risks are most paramount when the prospects are in excess of 300 meters of water. Here, in areas where the deltaic processes have died out and predominance of hydrocarbon-trapping-listric faults are least, gravity tectonics have created toe thrusts, shale diaspirs, and imbricate thrust structures.

Oyo-1, which is being drilled in 300 meters of water off Nigeria, excites geologic interest because of these risks. BP-Statoil have said categorically that the bulk of well data available from the shelf is largely irrelevant to the play type likely to be encountered. In this well, the objectives are basin turbidites and ponded slope (Ragnhild & Ore, AAPG 1995). Such are the targets that will interest explorationists in the near future in this area. Much of the area of interest 930-2,000 meters) is in the intraslope sub-basins and imbricate thrust structures which may have incorporated in them sandy deepwater facies. The first nine wells, to be drilled in the July-December 1996 period , will determine precisely what structural relationships between these various features are the best for hydrocarbon exploration in what is potentially Africa's largest deepwater oil province.