GEOLOGY, HYDROCARBON POTENTIAL OF RIO MUNI AREA, EQUATORIAL GUINEA

Don Ross, Norman Hempstead
EMS Ltd.
Oxted, England

The Republic of Equatorial Guinea, located in the oil producing province of "Test Africa, consists of three islands and an enclave in continental Africa with a total surface area of about 28,000 sq km (Fig. 1).

The islands are in the Gulf of Guinea. The largest, Bioko, lies off Nigeria and Cameroon. The continental enclave, Rio Muni, is bounded to the north by Cameroon and to the east and south by Gabon. The coastal basin of Rio Muni, which is the subject of this article, contributes the major portion of areas offered in the current exploration licensing round,

Some 5,275 km of seismic data have been recorded the past 10 years covering most of the offshore and onshore areas of Rio Muni. The quality of seismic data is generally good. Data from all six wells drilled in the area and an aeromagnetic survey of the whole onshore and offshore are also available.

WEST AFRICAN SETTING

The West African passive margin formed during the early Cretaceous rifting, and subsequent drifting, of South America from Africa.

Rifting propagated from south to north, the initiation of rifting occurring in the Neocomian in the South Atlantic but not until late Aptian in the Gulf of Guinea.

Although the age of rifting varied, during the Aptian an extensive salt lake developed that extended northwards from the Walvis ridge in Angola through Congo, Gabon, and Equatorial Guinea, finally pinching out in Cameroon (Fig. 2).

Rio Muni lies within this regional petroleum province. Salt is a critical component of the hydrocarbon system as it acts as a regional seal for presalt targets and also as a mechanism for generating structures in the post-salt section,

Exploration in the West African salt basin has targeted both presalt and postsalt objectives. Presalt production comes from continental lacustrine to fluvial sandstones, sourced by lacustrine shales, trapped typically in tilted fault blocks and sealed by intraformational shales and ultimately salt.

Postsalt production predominantly derives from marine Albian to Cenomanian carbonate and clastic reservoirs and from Senonian turbidites (Fig. 3). These are sourced either by lacustrine presalt shales or by postsalt marine shales.

Seals are Cretaceous or Tertiary marine shales, and trapping mechanisms are diverse, though commonly related to halokinesis, Minor production also comes from Tertiary turbidite sands in Gabon and Angola.

In the West African salt basin proved ultimate reserves exceeding 10 billion bbl of oil are identified, of which more than 2 billion bbl have been produced.

Other countries in the basin are Cameroon (Douala basin) with about 56 wells drilled that identified more than 500 million bbl of oil equivalent, mostly gas; Gabon 738 wells, 2.963 billion BOE; Congo 231 wells, 1.996 billion BOE; and Angola 672 wells, 5.076 billion BOE.

Alain Perrodon wrote recently that Africa appears to be irregularly and only moderately explored but has one of the highest technical finding rates. Many basins such as the Sahara and Gulf of Guinea, two rich petroleum provinces today, have shown numerous dry wells before discovery.1

In the Congo, with a coastline length similar to Rio Muni's, the drilling of about 231 wells has established known reserves of about 2 billion bbl of oil. Rio Muni has only six wells.

EXPLORATION HISTORY

Hydrocarbon exploration in Equatorial Guinea began in the late 1960s and early 1970s, when two wells were drilled in the offshore.

Both dry holes, Rio Muni Al in the south in 1968 and Rio Muni 1 in the north in 1971, were drilled--before the acquisition of modern seismic data--on regional highs lacking many of the key reservoir sequences now recognized elsewhere.

In 1985 the onshore N'Dote 1 was drilled based on a widely spaced reconnaissance grid of seismic lines. The well drilled directly into the middle Aptian, which contained continental sandstone reservoirs and source rocks.

At the N'Dote 1 location reservoirs were of poor quality and source rocks overmature for oil due to deep burial prior to erosion of the post-Aptian section. Away from this well location some substantially younger section exists, but this interior basin remains unexplored.

Following a seismic survey in 1984, attention returned to the offshore with the Benito 1 (1986) and Matondo 1 (1988) wells (seismic line A, Fig. 4). Benito 1 targeted an unconformity-truncated stratigraphic trap containing Albian reservoirs.

The Albian sediments showed encouragement for the presence of high energy level deposition with moderate to good porosities being present in oolitic carbonates and sandstones. Permeabilities here were poor, but considerable potential exists for lateral improvement in reservoir quality.

The nearby Matondo 1 well drilled through a thin Albian section into upper Aptian targets and bottomed in Aptian salt.

Good quality source rocks were encountered in the Aptian; oil shows were present in lacustrine sandstones, but the reservoirs were of only moderate quality at the Matondo 1 location. Again, regionally, significant potential exists for lateral improvement of reservoir quality both on depositional and diagenetic criteria.

The East Eviondo 1 well, drilled in 1991, is the most recent exploration well in Rio Muni. Oil shows were encountered in moderate porosity sandstones in the primary Aptian target.

Good porosity sand-stones, interbedded with limestones, were present in the overlying Albian but no oil shows were found; this section comes very close to surface at the well location and probably lacks a good vertical seal (seismic line B, Fig. 5).

BASIN DEVELOPMENT

For the success of future exploration in Rio Muni it is vital that an improved understanding is achieved in the basin's tectono-stratigraphic evolution. This should ultimately provide a framework for the understanding of trap formation, reservoir prediction, and play development. The model summarized below and in Fig. 3 is based on available seismic and well data, set within the framework of the overall evolution of the West African salt basin.

Rifting in Equatorial Guinea probably initiated in the pre-Aptian, which is as yet undrilled. In Gabon the northward propagation of the West African rift gave rise to Neocomian rifting south of the N'Komi transfer zone (Fig. 1) and slightly younger Neocomian/Barremian rifting in the north . 2

Geologically, Equatorial Guinea is separated from North Gabon by the Fang transfer zone, across which the age of rifting may young slightly northwards. By the early Aptian West African rifting had resulted in the formation of a salt basin extending from Angola to southern Cameroon.

Whereas in Gabon and southwards salt persisted through the Aptian, in Rio Muni the upper Aptian is represented by lacustrine sandstones and source rocks, proven both by wells and coastal outcrops (Fig. 3).

By the early Albian, marine conditions were established. Rifting, which had died out by this time further south in West Africa, continued in Rio Muni. This resulted in a high degree of structuring, enhanced by halokinesis, in the postsalt section. Excellent potential exists for the development of high energy, good quality reservoir facies in the Albian on the crests of rotated fault blocks, a situation not tested by past wells.

Shallow marine conditions, though predominantly in clastic facies, continued into the Cenomanian (Fig. 3). The Cenomanian has been thin in past wells due to subsequent erosion; however, seismic evidence indicates the preservation of locally thickened Cenomanian sections away from these locations. Although not drilled in Rio Muni, by analogy with Gabon the Turonian is probably represented by mixed clastic and carbonate sediments, with good source quality predicted in deep marine facies to the west (Fig. 3).

In the early Senonian, major erosion of the marine slope formed a widespread unconformity. The mechanism of formation of this unconformity, which is also evident in northern Gabon, remains poorly understood. However, at many locations it had the positive effect of placing a marine shale seal over potential Cenomanian and Albian reservoirs. In the western part of the study area seismic evidence suggests that the Senonian shale is replaced by a sandprone turbidite package analogous to the key Senonian reservoirs of offshore central Gabon (Figs. 1, 3).

Tertiary well control is lacking in Rio Muni. Subsidence and marine conditions, however, probably continued through the Paleocene and Eocene prior to regional uplift (particularly in the east) and westward tilting during the Oligocene. Neogene to recent sediments comprise prograding marine shale-dominated facies that are important in providing overburden for source rock maturation.

The tectono-stratigraphic evolution of Rio Muni establishes not only an improved local understanding but also geological criteria for comparisons with oil producing areas elsewhere in the West African salt basin. Several highly prospective plays untested by existing wells are now identified in the presalt and postsalt sections.

PRESALT PLAY

In the presalt the key play is tilted early rift fault blocks sealed by Aptian salt.

Reservoirs will be continental lacustrine or fluvial sediments with lacustrine shales providing the source. This play, which contains more than 1.5 billion bbl of oil reserves in adjacent Gabon, is entirely untested in Equatorial Guinea.

An example of this play is illustrated by the tilted fault block at the Benito 1 and Matondo 1 locations (Fig. 4).

At this location, unless presalt sands were of better depositional facies than the postsalt Aptian sands, it is possible that reservoir quality would be poor due to late Cretaceous and Tertiary burial. However, there are many locations where presalt fault blocks, occurring at shallower depths, represent attractive targets.

POSTSALT APTIAN PLAY

Rio Muni appears to be unique in West Africa in having a postsalt Aptian section containing good quality source rocks and sandstones reservoirs.

Intraformational shales should also act as good seals. Potential traps include rotated fault blocks, rollover anticlines, and salt swells. In Benito 1 and East Eviondo 1 wells Aptian sandstones had oil shows but were of only moderate reservoir quality. These wells represent the only two data points for the whole of Rio Muni.

Significant scope thus exists for a lateral improvement in reservoir quality from both depositional and diagenetic criteria. Developing the current understanding of tectonic controls on sedimentation and on burial and digenesis would help to enhance the prospectivity of this new play.

ALBIAN PLAY

Albian reservoirs sustain major oil production in Congo and Angola. There, syndepositional tectonic activity was important in creating local highs where energy carbonates and sandstones accumulated.

Good porosity Albian reservoirs were found in Rio Muni in oolitic carbonates in Benito 1 and sandstones in East Eviondo 1. However, neither of these locations targeted rotated fault block crests where the best quality reservoirs are predicted in shoals on syndepositional highs. Elsewhere in the study area rotated fault blocks show clear evidence for syndepositional variation within the Albian section (seismic line B, Fig. 5, and seismic line C, Fig. 6).

These plays, which are analogous to those in Congo and Angola, are highly prospective and remain untested in Rio Muni. Source would be provided by postsalt Aptian lacustrine shales and seal by Cenomanian or ultimately, Senonian shales.

CLASTIC PLAY

Away from Benito 1 and East Eviondo 1, where Cenomanian sediments are thinned by erosion, the Cenomanian section locally thickens and is an attractive target.

Seismic character supports the presence of laterally extensive sand-prone sections that are structurally trapped (seismic line C, Fig. 6).

Cenomanian sandstones in similar settings provide significant production in Congo and Angola.

SENONIAN/PALEOGENE PLAY

Off central Gabon more than 1.4 billion bbl of oil is reservoired in Senonian turbidite sands.

In Rio Muni, the Benito 1 and Matondo 1 wells encountered marine shales, probably deposited in an outer shelf to upper slope setting. This facies represents an important seal. However, westwards, in the present intermediate water depths, channeled and mounded seismic character strongly suggests that the Senonian contains sandprone packages (seismic line D, Fig. 7).

Trapping mechanisms for these sands would be largely stratigraphic by either depositional pinchout or shale channel truncation, as in the Namorado, Enchova, and Bonito fields in the Campos basin of Brazil.3

Locally, structural traps may also exist. Good source rocks are predicted downdip in Turonian to Senonian marine shales, known as a source in Gabon. The thickness of sediments overlying these source rocks in deeper water off Rio Muni suggests oil maturation is likely.

SUMMARY OF PLAYS

Rio Muni has many varied potential plays, mostly as yet untested. As well as the plays detailed here potential exists for salt tectonic related stratigraphic traps and downthrown plays. Tertiary channel sands also prove productive elsewhere in West Africa.

Despite the high degree of structuration and the variety of hydrocarbon plays available, Rio Muni remains the least explored area of the West African salt basin.

LICENSING ROUND

An area of more than 13,000 sq km is being offered in the current licensing round by the Ministry of Mines and Hydrocarbons.

This offering consists of seven offshore and five onshore blocks in the Rio Muni area and the unlicensed deep water areas around Bioko island (Fig. 1).

Applications for exploration licenses are to be submitted to the ministry by Dec. 31, 1993. Applications will be evaluated based on proposed work commitments, state participation, and a signature bonus.

The ministry has signed an agreement with EMS Ltd., Oxted, Surrey, England, to assist in promoting the licensing round.

The applicable law concerning hydrocarbon exploration and production in Equatorial Guinea is Decree-Law No. 7/1981 passed on June 16, 1981 (see table).

REFERENCES

Perrodon, Alain, Overview of African petroleum systems, OGJ, July 12, 1993, p. 115.
Teisserenc, P., and Villemin, J., Sedimentary basin of Gabon--geology and oil systems, AAPG Memoir 48, Divergent/passive margin basins, Edwards, J.D., and Santogrossi, P.A., eds., 1990, pp. 117-200.
Guardado, L.R., Gamboa, L.A.F., and Luccesi, C.F., Petroleum geology of the Campos basin, Brazil, a model for a producing Atlantic-type basin, AAPG Memoir 48, Divergent/passive margin basins, Edwards, J.D., and Santogrossi, P.A., eds., 1990, pp. 3-80.