GEOLOGY, POTENTIAL OF ALGOA, GAMTOOS BASINS OF SOUTH AFRICA

Jean A. Malan
Soekor (Pty.) Ltd.
Cape Town

As the Republic of South Africa is accepted back into the world community it is becoming possible for Soekor (Pty.) Ltd., the petroleum exploration company, to offer areas for oil and gas exploration in the South African offshore.

These blocks will be available to companies for sublease or in participation with Soekor.

The Algoa and Gamtoos basins on the southeastern margin of South Africa are complex rift-type basins that are present in both onshore and offshore (Fig. 1).

The onshore portion of the Algoa basin comprises nearly 4,000 sq km with the offshore Algoa and Gamtoos basins made up by areas of some 4,000 sq km and 3,000 sq km, respectively.

Both basins are situated at the eastern edge of the continental shelf, the Agulhas bank, where water depths are generally less than 200 m but increase rapidly to beyond 500 m in the south at the present day shelf edge (Fig. 1). The southwestward flowing Agulhas current is concentrated along the shelf edge.

GEOLOGY, TECTONIC SETTING

The late Mesozoic basins of South Africa lie at the southernmost tip of the African plate.

The Outeniqua basin, extending from the Agulhas arch in the southwest to the Port Alfred arch in the northeast, comprises a complex of en-echelon half-grabens. These half-grabens developed during the early stages of rifting prior to the separation of east and west Gondwana.

The Algoa and Gamtoos basins comprise the most easterly half grabens in the Outeniqua basin and are defined by the St. Francis, Recife, and Port Alfred arches (Fig. 1), composed of Paleozoic Cape supergroup rocks. These arches follow the structural grain of the Permo-Triassic Cape fold belt.

The Gamtoos basin is essentially a simple half-graben feature (Fig. 2) controlled by the Gamtoos fault extending deep into the crust and displaying a complex history. The onshore portion of the Gamtoos fault has a throw of about 3,000 m, but offshore this increases to about 12,000 m. Further major faults in the offshore Gamtoos basin occur on the eastern flank of the St. Francis arch (Fig. 2).

The more complex Algoa basin comprises three sub-basins, the Port Elizabeth, Uitenhage, and Sundays River troughs (Fig. 1). The latter is almost entirely onshore and contains a sequence of more than 4,200 m of Portlandian to Hauterivian sediments.

Only the proximal part of the Uitenhage trough is developed onshore. This half-graben, bounded to the northeast by the Coega-St. Croix fault system, widens and deepens offshore where it is divided by the southeast to northwest trending Uitenhage fault (Fig. 3). In the offshore Port Elizabeth and Uitenhage troughs, top of basement (Horizon D) attains depths of 6,500 m and 8,000 m, respectively.

The sediments of all of the Gamtoos and Algoa basins have been divided into four major units:

Synrift (horizon D to 1At1).
Early drift (1At1 to 6At1).
Canyon fill (13At1 to 14At1).
Thermal subsidence (post-14At1).

An angular unconformity (1At1) at the top of the synrift succession is regarded as the drift-onset unconformity. Onshore drilling has often terminated in economic basement of Ordovician to Silurian Table Mountain group quartzites or Devonian Bokkeveld group slates. Deep drilling offshore has intersected basement rocks only on the flanks of basement arches and on basement highs.

As east and west Gondwana separated along the dextral Agulhas/Falkland transform, structural features-attributed to the tectonic strain-developed. These are preserved in the form of several inverted faults and anticlinal features in the Algoa and Gamtoos region, during the Barremian to early Aptian, resulted in major basinwide erosion and the incision of several canyons into the synrift and early drift sediments (Figs. 2, 3). Consequently 6At1 and 13At1 form a compound unconformity in both the basins.

Canyon infilling commenced in the early Aptian (post-13At1) and terminated in the Middle Albian at 14At1. The canyon fill is overlain by late Albian to Cenomanian (15At1) sediments (Fig. 3). A further phase of erosion occurred in the late Cretaceous with a number of channels eroding into the drift package of the southern Algoa and Gamtoos basins in the area of the paleo-shelf break. At some localities this Santonian erosion was quite intense, even cutting into the synrift package.

Since the mid-Aptian the southern offshore has experienced a phase of thermal subsidence during which the Gamtoos and Algoa basin margins were uplifted relative to the subsiding basin centers. This resulted in erosion of the thermal subsidence package marked by the truncations of 15At1 and 22At1, the latter being the regional unconformity marking the end of Cretaceous sedimentation (Fig. 4). Offshore Cainozoic sediments are thin with similar Pliocene to Holocene deposits preserved over parts of the onshore Algoa basin.

PETROLEUM GEOLOGY

Dry gas to oil prone source rocks are present in the synrift, the early drift, and the canyon fill units (table).

Up to 215 m of Kimmeridgian to Portlandian dry gas and, in places, wet gas to oil prone source rocks were intersected by boreholes in the central and southern parts of the Gamtoos basin. These source rocks have ultimate yields that peak at 3 kg/metric ton but, because of their great depth of burial, their original potential could have been 4 kg/metric ton or more.

Good oil shows are associated with the best source rocks and occur in the Port Elizabeth trough. Boreholes in this half-graben intersected an average of 60 m of marginally mature Portlandian, anoxic marine shales with a yield of 8.1 kg/metric ton of rock.

If this source sequence continues into the deeper parts of the trough as indicated by the seismic data, then the improved maturity makes the potential of this poorly explored half-graben high. Similar mature oil prone Portlandian source rocks are expected to be present in the unexplored southeastern parts of the Uitenhage trough.

Hydrocarbon shows in the onshore Sundays River trough are sourced from late Jurassic lacustrine oil prone source rocks (Fig. 4). The potential of these shales is estimated to be 8-12 kg/metric ton. Few samples were analyzed after the mid-1970s, but the available values of organic matter and extractable organic carbon indicate good potential and support the few pyrolysis results available.

In the offshore Uitenhage trough an areally restricted, 130 m thick, dry- to wet-gas prone source sequence of latest Valanginian to Hauterivian age occurs in the hanging wall of the Uitenhage fault (Fig. 3). Similar immature, dry gas to oil prone source rocks are present in the central part of the Gamtoos basin (table). Up to 130 m of immature gas prone source rocks occur in the fill of the Algoa Canyon (Fig. 3).

Reservoir quality sandstones with maximum porosities of 25% and permeabilities of up to 400 md are developed in the Algoa basin, where sandstones comprise up to 40% of the horizon D to 1At1 (synrift) succession in the Uitenhage trough. Slightly poorer reservoir quality sandstones of Albian age have been encountered in the canyon fill sequences.

In the Gamtoos basin potential reservoir sandstones are sparsely distributed but occur as shallow marine sandstones present in the Kimmeridgian in the western part of the basin and in the late Valanginian sequence. Several stacked gas charged submarine fan sandstone reservoirs of Kimmeridgian to Berriasian age were also intersected in the southern part of the Gamtoos basin.

Although geothermal gradients in the Algoa and Gamtoos basins are low (3/100 m on average), adequate maturity is attained. The onset of the main stage of oil generation was favorably timed for migration into pre-existing traps from the late Cretaceous onwards.

Most synrift reservoirs are overlain by regionally developed claystone seals. Unconformities, subcrops, anticlines, tilted fault blocks, and canyon erosion are characteristic features of these basins and testify to a complex tectonic history which, together with stratigraphic traps, makes for exciting exploration opportunities.

OIL, GAS PROSPECTIVITY

Exploration for hydrocarbons in the Algoa and Gamtoos basins began in the early part of this century with the drilling of the Swartkops borehole east of Port Elizabeth in the onshore part of the Uitenhage trough. Since then a number of companies have been involved in the search for hydrocarbons.

Twenty-two boreholes onshore and 19 offshore have been drilled in the Algoa and Gamtoos basins. No commercial production of oil or gas has been achieved despite encouraging hydrocarbon shows. Onshore, a drillstem test produced 36 gravity oil at an insignificant flow rate.

Oil shows and log evaluation indicated the presence of reservoired oil in a nearby borehole, but drillstem testing was unsuccessful. Subsequent drilling of adjacent wells failed to confirm any reservoired hydrocarbons, and it was concluded that the oil was locally trapped in fractures.

Offshore, hydrocarbon shows were encountered in boreholes drilled in the Port Elizabeth and Uitenhage troughs and in the Gamtoos basin. No drillstem tests were performed offshore, but shows have been sufficiently encouraging to continue exploration. Also encouraging is a 630 sq km wet gas to oil Sniffer anomaly recorded in Algoa bay. This anomaly was centered in the area overlying the northern extent of the Algoa canyon and the St. Croix fault (Fig. 3).

The distribution of reservoirs and source rocks suggests that the best hydrocarbon potential may lie in the undrilled southern Port Elizabeth and southern Uitenhage troughs and in the poorly explored southern parts of the Gamtoos basin.

The abundance of reservoir quality sandstones in the northern Uitenhage trough combined with the presence of the Sniffer hydrocarbon anomaly upgrades this part of the Algoa basin. Encouraging hydrocarbon shows were also present in Albian sandstones at the base of the Algoa canyon, with similar untested stratigraphic traps present to the south.

An onshore data set of 22 boreholes and an offshore data set in the form of 19 boreholes and comprehensive multichannel seismic coverage could form the basis for exciting opportunities in these structurally complex basins. In addition there are a number of identified prospects and prospect leads in these basins in water less than 300 m deep.

Both basins are semi-explored and contain known reservoir units, several petroleum charge systems, regional topseals, and numerous traps. The good temporal relationship between these various factors have resulted in a good potential for undiscovered petroleum accumulations.