SOUTH AFRICA OFFERS EXPLORATORY POTENTIAL IN VARIETY OF BASINS

David S. Broad, Stephen R. Mills
Soekor (Pty.) Ltd.
Cape Town

Southern Africa has not been bypassed by the political revolution of the last few years

Namibia has established itself as a respected member of the family of nations. The civil war in Mozambique has been suspended as the leaders negotiate their way to a lasting peace. And this process is perhaps even further advanced in South Africa.

These changes, as well as the potential for peace in Angola, will significantly improve the growth potential of all the countries in the region and consequently energy demand of the subcontinent.

While the future suspension of the oil embargo against South Africa will no doubt help revitalize the region's most powerful economy, a move away from dependence on coal as the major local energy source is also likely.

This could be accomplished through regional cooperation and development were it not for the ongoing conflict in Angola, the only producer of oil and gas in the Southern African Development Community. Even with world oil prices in the doldrums, massive foreign exchange savings would result from a domestic source, and in line with world trends the possibility of harnessing the gas resources of the region is increasingly seen as a possibility.

For the present, those resources remain to be defined. But ENH of Mozambique is pursuing an appraisal program for Pande field with World Bank funding, while Shell and its partners are considering possibilities of Kudu field in Namibia.

And while South Africa's own national oil company, Soekor, has had limited success with its search for oil during the apartheid years, offshore F-A gas field is in production, and the potential for hydrocarbons-gas in particular-requires a great deal more investigation.

Our colleagues have prepared a series of articles on basins off South Africa, three of which have appeared-Bredasdorp basin (OGJ, Dec. 21, 1992, p. 109), Orange basin (OGJ, Jan. 25, p. 106), and Gamtoos and Algoa basins (OGJ, Nov. 15, p. 74). These articles were prepared in anticipation of the completion of political reform and of the start of a licensing round, possibly during 1994.

This article draws together summaries of aspects thought to be most pertinent to petroleum exploration.

COUNTRY OVERVIEW

The basins, which originated during the breakup of southern Gondwana, together cover an area of 200,000 sq km.

In recent years a number of small oil fields have been discovered by Soekor in the Bredasdorp basin-mainly in deepwater submarine fan-channel complexes. However, the greater potential is for gas. Several gas fields have already been discovered.

South Africa's first natural hydrocarbon production came on stream in 1992 to feed the Mossgas synfuels plant near Mossel Bay on the south coast. A recent independent review confirmed that significant potential remains - primarily in the Orange, Bredasdorp, and Pletmost basins but especially in the unexplored Southern Outeniqua basin, which holds the potential for giant oil fields.

South Africa's infrastructure is well developed with, by African standards, an exceptional road network, modem international airports, and several harbors capable of handling all but the largest ships. All the structural components for the offshore production platform were manufactured and assembled in the country, with the result that the yards concerned are now involved in construction of platforms for installation elsewhere in the region.

The fiscal regime has been assessed by independent consultants as comparatively generous.

Development of the region's energy potential would do much to contribute to stability of the subcontinent through generation of wealth in general and sorely needed jobs in particular. The energy demand, facilities, and skills are all in place-the geology is the last remaining area of uncertainty for a successful project.

The offshore basins of the Republic of South Africa lie along the southern margins of the African plate. They originated in the middle to late Jurassic during the breakup of southern Gondwana (Fig. 1).

The western margin of South Africa is a divergent plate margin underlain by synrift grabens, whereas the southern and eastern margins are pull-apart grabens truncated by a major transform.

This major lineament, known as the Agulhas-Falkland Fracture Zone, is 1,200 km long. It began right lateral movement at the time of continental separation. This resulted in widespread structural deformation of adjacent basins and accounts for the wide variety of structural traps.

The West Coast Margin extends from the southern tip of the continental shelf to the Namibian border and includes most of the Orange basin. The Outeniqua basin extends from Cape Town to Port Elizabeth and contains the Bredasdorp, Pletmos, Gamtoos, Algoa, and Southern Outeniqua basins, which are strictly subbasins. The Durban and Zululand basins occupy the narrow continental shelf north of Durban.

WEST COAST MARGIN

The West Coast Margin covers approximately 130,000 sq km and is significantly underexplored, with sparse well control.

The Orange basin has good hydrocarbon potential. Half of the 30 wells drilled encountered some form of hydrocarbons. Gas has been found in the drift succession and oil in the synrift succession (Table 1). Trapping mechanisms in the synrift are generally stratigraphic, whereas in the drift traps are predominantly of a structural and combination type.

A recent seismic survey in the deepwater areas of the West Coast Margin has revealed a number of prospects in water less than 450 m deep. The area represents a large, relatively untested frontier basin with known hydrocarbon accumulations and the potential for giant fields.

RESERVOIRS

Reservoirs in the synrift succession comprise fluvio-deltaic and lacustrine sandstones and conglomerates (Fig. 2). Those in the postrift succession range from fluvio-deltaic to deepwater sandstones.

The sand/shale ratio is generally high in the drift sediments on the shelf, with abundant fairways for sand transport out to the basin floor. Sandstones exhibiting excellent porosity and permeability have been encountered at depths of up to 4,000 m, although in some areas porosity and permeability have been degraded by secondary silicification.

SOURCE ROCKS

Three source rock intervals have been identified. Mature, oil-prone, lacustrine source rocks up to 60 m thick are present in the synrift interval. They had an original hydrocarbon potential of 9-11 kg/ton, locally exceeding 40 kg/ton.

Directly above the Early Aptian unconformity 13Atl, source rocks are regionally developed and range from gas-prone on the shelf to oil-prone farther west. They are up to 90 m thick and had an original potential of 3-9 kg/ton. In the Namibian sector of the basin they are up to 140 m thick with an original oil potential of up to 11 kg/ton. Beyond the shelf break maturity levels are expected to decline as the overburden thins (Fig. 3).

Gas prone source rocks averaging 30 m thick were deposited during the global Cenomanian/Turonian oceanic anoxic event immediately above the 15Atl unconformity. The potential of these source rocks is expected to improve basinward where they may become oil-prone.

TRAPS, MIGRATION

Traps tested thus far include domal and fault-controlled closures and stratigraphically defined lowstand plays and pinchouts.

Several play types have not been adequately tested, and plays located in water depths greater than 450 m require further evaluations.

Migration routes in the basin vary from short and direct in the grabens to medium to long distance farther offshore.

BREDASDORP BASIN

The Bredasdorp basin covers an area of approximately 18,000 sq km. Water depths are generally less than 200 m.

Since the drilling of the first well in 1970, some 90 wildcats, 46 appraisal wells, and 8 production wells have been drilled.

The basin contains F-A gas field, 85 km south of Mossel Bay in water 105 in deep. F-A is South Africa's first producing field.

Production began in 1992, gas and condensate being piped from a fixed platform to an onshore facility near Mossel Bay for conversion to liquid fuels.

RESERVOIRS

Wet gas production is from the upper part of the synrift shallow-marine succession along the northern flank of the basin (Fig. 4).

Several small gas fields have been discovered in this area in a gas fairway over 100 km long.

Reservoir quality in F-A gas field is highly variable due to differential development of secondary porosity, but reservoir porosity values are generally 11-16%. Permeability values attain 5(YO md.

Reservoir sandstones also occur within the drift succession in submarine fan-channel turbidite complexes which were emplaced during Aptian and Albian lowstands. These deposits host several small oil fields, which are currently being appraised.

Porosity is often secondary in origin with values in the range of 13-21%. Permeabilities are as high as 1,200 md but generally average 250 md.

SOURCE ROCKS

Five source rocks have been intersected in the drift succession and, in common with the other basins, are associated with highstands.

Kerogen types vary from dry gas to wet gas to oil-prone. The yield is typically 3-12 kg/ton with total organic content (TOC) values of 2.5-3.5%

The richest and thickest source rock, in the mid-Aptian 13A sequence, is up to 220 in thick and is oil to wet-gas prone. Large areas are currently in the oil window (Fig. 5).

Two wells have encountered thin lacustrine source rocks in the synrift succession, but the areal development of this facies is conjectural.

TRAPS, MIGRATION

The Bredasdorp basin contains a variety of traps, which ran-e from structural to stratigraphic to combination.

In the synrift succession, the F-A and other gas fields are characterized by domal and fault traps formed in the Early Valanginian.

in the drift succession, traps are more complex and comprise subtle domal and compactional drape features, in many cases with a stratigraphic component.

It is surmised that the source rocks that supplied the Bredasdorp basin gas fields are located in the central basin area, in which case long distance migration of about 30 km is envisaged.

Reservoir sandstones in the 13A submarine fan-channel complexes are enveloped by source shales; therefore, migration routes are short and direct.

Palaeogeothermal gradients range from 2.6 to 4.6 C./100 in. Burial history modeling indicates that the 13A source shales entered the oil expulsion window in the Late Cretaceous to Early Tertiary.

PLETMOS BASIN

The Pletmos basin covers an area of approximately 20,000 sq km and is subdivided into a number of half-grabens.

The first borehole in the basin was drilled on the Superior High in 1968 (Fig. 6). It resulted in a gas discovery that is currently being reevaluated.

Since then a further 39 wildcats and 6 appraisal wells have been drilled. Several encouraging gas shows were recorded.

RESERVOIRS, TRAPS

As in the Bredasdorp basin, the main reservoirs are shallow-marine sandstones of the latest synrift succession directly beneath the drift-onset unconformity (1At1).

In the drift succession it is likely that potential reservoir sandstones are developed within submarine fan-channel complexes associated with a lowstands.

Superior gas field is a structurally complex faulted subcrop closure. Similar structural traps have been drilled in the basin, and others remain to be tested.

Stratigraphic and combination traps are present within the drift succession but have rarely been targeted.

SOURCE ROCKS, MIGRATION

Organic-rich shales have been intersected in six drift sequences.

Kerogen types vary from oil-prone to wet-gas prone to dry-gas prone. The ultimate yield ranges from 3 kg/ton to I 0 kg/ton.

Wet-gas to oil-prone organic-rich shales up to 60 in thick are widespread in the 13A sequence and are currently in the oil-explusion window.

As in F-A gas field, the identity of source rocks that provided hydrocarbons to Superior gas field and other synrift reservoirs has not been established with certainty.

Earliest drift argillaceous sediments possess good source potential, are mature in the deeper parts of the basin, and probably supplied at least a part of the hydrocarbon charge, in which case migration distances of 5-20 km are likely.

GAMTOOS AND ALGOA BASINS

Nineteen wells have been drilled in the offshore parts of the structurally complex Gamtoos and Algoa basins.

Together with "sniffer" hydrocarbon anomaly in the Algoa basin, the wells provide evidence for regional hydrocarbon potential.

RESERVOIRS, SOURCE ROCKS

Good quality reservoir sandstones are rarely developed in the Gamtoos basin but are widespread in the Algoa basin, where porosities of 20% and permeabilities of 400 md occur.

Significant gas to oil-prone shales of Kimmeridgian to Portlandian age are present in the Gamtoos basin (Fig. 7). They have a generative potential of up to 3 kg/ton.

In the Port Elizabeth Trough of the Algoa basin, wells have intersected 60 in of wet-gas to oil-prone anoxic shales with generative potential of 8 kg/ton and TOC values up to 4.3% (Fig. 8).

Gas-prone source shales also occur in the early drift succession. Onset of the main stage of oil generation and expulsion was Late Cretaceous to Early Tertian,.

TRAPS, MIGRATION

Structural traps occur in several varieties in these basins due to proximity to the Agulhas-Falkland fracture zone.

Migration routes are probably complex and fault-assisted. Oil shows in basement quartzites indicate migration up the Gamtoos fault plane.

SOUTHERN OUTENIQUA BASIN

The Southern Outeniqua basin covers an area of approximately 22,000 sq km and encompasses the distal extensions of the Bredasdorp, Pletmos, Gamtoos, and Algoa basins that lie beyond the 300 in isobath (Fig. 1).

RESERVOIRS, SOURCE ROCKS

Major deep marine fan systems fed by canyons from the more proximal basins are prognosed to be present in the Aptian to Turonian interval and are expected to contain good quality stacked reservoir sandstones similar to those intersected in the 13A to 15A sequences in the Bredasdorp basin.

Shallow marine sandstones deposited in synrift half-grabens may also constitute excellent reservoirs.

It is inferred that the major source rocks in the proximal basins extend into the Southern Outeniqua basin.

Furthermore, the presence of lacustrine source facies in the synrift sequence would be consistent with current models of rift basin development.

TRAPS, MIGRATION

Structural traps in the synrift succession are expected to be similar to those in adjacent basins. In the drift succession, stratigraphic and combination traps are expected in submarine fan-channel complexes.

It is considered that some of the gas in synrift structures in the Bredasdorp and Pletmos basins has been derived from source rocks in the Southern Outeniqua basin. This implies long distance migration.

DURBAN, ZULULAND BASINS

The Durban and Zululand basins are underexplored; little is known of their hydrocarbon potential.

One of three wells drilled in the Durban basin provided indications of minor source rocks and thin sandstones with gas peaks (Fig. 10).

The offshore Zululand basin has not been tested, but dry onshore wells encountered thick Cretaceous sandstones without any indication of hydrocarbons.

CONCLUSIONS

Soekor's exploration efforts have conclusively demonstrated that South Africa's offshore sedimentary basins possess significant hydrocarbon potential.

In all basins where drilling has taken place there is evidence for hydrocarbons, reservoir sandstones, source rocks, traps, seals, and migrations.

Based on our present understanding, the most significant hydrocarbon potential lies in the undrilled Southern Outeniqua basin and in the deeper parts of the Orange basin, both of which may be regarded as prime frontier areas with the potential for giant fields.

There also remain significant opportunities for further discoveries of oil and gas fields in the Bredasdorp and Pletmos basins. A real wild card may be the Port Elizabeth Trough of the Algoa basin, where favorable reservoirs and some of the best source rocks occur.

ACKNOWLEDGMENT

We are grateful to our colleagues at Soekor for their support in providing much of the data for this article and to the management of Soekor for permission to publish it.

Copyright 1993 Oil & Gas Journal. All Rights Reserved.