Potential outlined in Southern Outeniqua basin off S. Africa

Jacques Roux
Soekor (Pty.) Ltd., Cape Town

Exciting frontier areas are available for exploration in the deeper waters off South Africa. One such unexplored area is the Southern Outeniqua basin (Fig. 1 [32,380 bytes]).

Based on modeling of the adjacent Pletmos and Bredasdorp basins, good reservoir and source rocks are prognosed, and large structures have been mapped within this untested basin of some 20,000 sq km, or 4,942,000 acres.

The Southern Outeniqua basin is situated off the south coast of South Africa within blocks 11 to 13 (Fig. 2). This basin consists of the southeastern deepwater extensions of the Bredasdorp basin,¹ Gamtoos/Algoa basins,² and Pletmos basins (beyond the 300 m isobath).

Exploration results from the shallower water part of the Pletmos basin has provided a sound basis for understanding the regional distribution and quality trends of petroleum source rocks. A recent publication³ places them in a sequence stratigraphic framework, which provides a key tool for effective prediction and exploration of the adjacent Southern Outeniqua basin.

Geology

Rifting

The combined four sub-basins (Bredasdorp, Pletmos/Infanta, Gamtoos, and Algoa) and their contiguous deepwater extension, referred to as the Southern Outeniqua basin, form a large intracratonic rift basin, the Outeniqua basin. This basin developed during the middle to late Jurassic, before the separation of east and west Gondwana, and extended onto what is known today as the Falkland plateau.

The northeastern and southwestern flanks of the Pletmos basin, the St. Francis arch and Infanta arch, are elongate basement highs (Fig. 2 [42,853 bytes]). Basement in the Pletmos basin comprises slates and quartzites of the Ordovician to Devonian Cape Supergroup.

The normal faults associated with rifting are parallel to the compressional tectonic grain of the Permo-Triassic Cape fold belt. The St. Francis and Infanta arches are bounded by major normal faults between which the Pletmos basin depocenter is developed.

The early rift fill consists of thick Kimmeridgian age sediments that filled a number of southeasterly trending grabens during horizon D (top basement) to horizon O times (Figs. 2, 3). Some of these early depocenters, like the Plettenberg graben and the Southern Outeniqua basin, are expected to contain Kimmeridgian oil-prone shales, similar to those intersected in the adjacent Gamtoos and Algoa basins2 and in the Deep Sea Drilling Project boreholes on the Falkland plateau.

Early fill is overlain by thick aggradational fluvial sediments in the northern Pletmos basin and marginal sandstones in the southern Pletmos basin. These sediments were sourced directly off the flanks of the basin and down the axis of the grabens in a south-easterly direction.

The late synrift interval from horizons O to 1At1 comprises fluvial, shallow marine, and shelf deposits of Portlandian to Valanginian age (Fig. 3 [26,408]). The sandstone content of the entire synrift succession increases towards the Southern Outeniqua basin in a southwesterly direction away from the sand-starved Plettenberg graben.

Drifting

During the Valanginian, right-lateral shear stresses developed along the Agulhas-Falkland fracture zone, a major Gondwana break-up structure. This resulted in folding and strike-slip movement along existing normal faults. The resultant right lateral movement along the fracture zone separated the Falkland plateau from the African plate and bisected the Outeniqua rift basin.

The angular unconformity marked by horizon 1At1 at the top of the synrift succession is regarded as the drift-onset unconformity (Fig. 3). It is highly erosional on the basin flanks and on other basements highs. The Outeniqua sub-basins subsided, resulting in deep marine, poorly oxygenated conditions over most of their extent.

During a transitional phase between 1At1 and 6At1, also characterized by transform tectonics, an aggradational onlap infill succession of deep marine claystones and thin bedded turbidites of late Valanginian to Hauterivian age (Figs. 3, 4, and 5 [30,532 bytes]) was deposited. Good quality wet gas to oil-prone shales are postulated to occur at the base of this interval over the Southern Outeniqua basin (Fig. 1). Characteristics of petroleum source rocks (from well data adjacent to the Southern Outeniqua basin) are shown in Table 1 [14,311 bytes].

The Hauterivian to mid-Aptian (6At1 to 13At1 interval) is characterized by high energy shelfal progradation from the northern margin of the Pletmos basin (Fig. 3). Shelf to shallow marine sandstones occur around the northern rim of the basin and across the entire Infanta embayment. Slope and basin floor fan sandstones have been proven by drilling toward the south, downdip of the paleontological shelf-edge. Good reservoirs are expected within prognosed deep marine fan and channel sandstones in the Southern Outeniqua basin.

Source shales varying from dry gas to wet gas and oil prone have been intersected in the southern Pletmos basin and Plettenberg graben and are expected to follow the established regional trend of improvement in quality towards the Southern Outeniqua basin (Table 1). They presently fall in the wet gas to oil maturity window.

The development of the mid-Aptian unconformity (13At1) is also associated with the deposition of an extensive 13A lowstand wedge prognosed to be present throughout most of the Southern Outeniqua basin. This was followed by a period of relative sand starvation over a large area of the basin during which time organic rich shales were deposited in the southern Pletmos basin and the Southern Outeniqua basin.

A high subsidence rate during this period diminished the effect of eustatic sea level changes, which resulted in an aggradational shelf buildup throughout late Aptian to mid-Albian times (Fig. 3). The late Aptian to Cenomanian sediments just below 15At1 prograded from the northwestern rim of the basin (Fig. 4). [39,490 bytes] The deep marine intervals in the 13A to 15A sequences over the Southern Outeniqua basin and the southern Pletmos basin remain untested, but the regional geological model suggests that deep marine fan systems fed by canyons from the proximal parts of the basin can be expected.

Wet gas to oil-prone source shales have been intersected in the southern Pletmos basin and are expected to follow the established regional trend of improvement in quality and thickness towards the Southern Outeniqua basin.

Exploration history

The first borehole in the Pletmos basin, Ga-A1, was drilled in 1968. It produced gas at potentially commercial rates (22 MMscfd) from synrift shallow marine sandstones and fractured quartzite basement of Ordovician to Devonian age.

To date a total of 38 wildcats, mostly on synrift structures, have been drilled throughout the Pletmos basin and Infanta embayment north of the Southern Outeniqua basin. Gas flow rates between 24 and 5 MMscfd with minor amounts of NGL were measured.

Sandstones from 1,565-2,500 m below kelly bushing have porosities of up to 25%, averaging between 11% to 18%, and permeabilities which range between 10 and 100 md, with a maximum of 450 md. One test performed within the fractured Table Mountain Group quartzite basement flowed 11 MMscfd of gas.

Boreholes drilled in the southern Pletmos basin intersected gas-saturated sandstones within the synrift succession. It is considered that a large percentage of the dry gas in synrift reservoirs has been derived by updip migration from early-rift shales (Kimmeridgian) lying within the Southern Outeniqua basin.

This area is regarded as a major hydrocarbon kitchen with multiple drift source rocks lying within the oil window.

Future opportunities

The Southern Outeniqua basin is considered a very promising frontier area.

The inferred distribution of reservoirs and source rocks in the untested Southern Outeniqua basin suggests that there is substantial potential in this large 20,000 sq km, 4,942,000 acre area. Exploration here would require relatively deepwater drilling (in excess of 300 m).

A number of untested synrift structures have recently been mapped. These domal structures are large, ranging from 300 to 1,600 million bbl, or 500 to 2,750 bscf gas (excluding additional subcrop potential). Deep marine fans developed within the drift succession are expected to contain oil and gas sourced from the same succession. These fans are expected to include good quality reservoir sandstones similar to those intersected in the 13A and 14A sequences in the Bredasdorp basin to the west.

This frontier area (comprising Blocks 11, 12, and 13) is available for sub-lease applications on a noncompetitive basis.

The distance offshore of the untested but potentially prospective area varies from 55-130 km, and seismic coverage is reasonable to good. The nearest deep-water harbor, Port Elizabeth, is 80-250 km to the northeast.

Acknowledgments

I thank colleagues for their input in compiling and presenting the data and the Soekor Petroleum Licensing Unit management for permission to submit this article for publication.

References

Burden, Paul L.A., Soekor, partners explore possibilities in Bredasdorp basin off South Africa, OGJ, Dec. 21, 1992, p. 109.

Malan, Jean A., Geology, potential of Algoa, Gamtoos basins of South Africa, OGJ, Nov. 15, 1993, p. 74.

AAPG Studies in Geology, Vol. 41, 1995.

The Author