A recent oil discovery shifts the focus of exploration to Angola's southern deepwater shelf.

The deepwater Kwanza Basin is set to become Angola's next exciting play area following the recent announcement of an oil discovery in Exxon's Semba-1 well. This drilling success has demonstrated the elements of a viable petroleum system in the basin and extended Angola's deepwater oil play area some 310 miles (500 km) to the south from the prolific Lower Congo Basin.
The Kwanza Basin offers one of today's more attractive frontier exploration opportunities in Africa. Covering some 48,200 sq miles (125,000 sq km), the basin has the potential for large discoveries, possessing the same salt-influenced geology, good-quality Tertiary and Cretaceous reservoirs and effective petroleum source rocks as its successful neighbor. Exploration along this petroliferous trend could significantly add to the estimated 6 billion-plus bbl of recoverable reserves found on Angola's deepwater shelf.
Early drilling in the shallowwater tract of the basin targeted the Albian limestone raft play with disappointing results. Typically the wells drilled top Albian closures and encountered pay in poor-quality reservoirs. However, the Semba-1 discovery, which targeted younger formations, revealed the area's potential. The well flowed 3,039 b/d of oil from two horizons, rumored to be Oligocene and Cretaceous. These results shift the focus of attention from carbonates to probable deepwater sandstone reservoirs with many similarities to those in the Lower Congo area.
Sonangol is planning to offer open areas within the basin for licensing later this year.
Basin development
The Kwanza Basin is defined as the continental shelf and adjacent continental area between latitudes about 8°30´S and 14°00´S. Water depth reaches 11,150 ft (3,400 m) in the designated ultradeep areas.
In common with other areas of the greater West African Salt Basin, the Kwanza Basin developed in the Early Cretaceous as a response to continental rifting that predated Atlantic separation. The area accumulated thick sequences of continental and lacustrine facies sediments prior to postrift marine flooding in the Aptian. At this time, the area became part of the continuous salt basin stretching from northern Namibia to southern Cameroon. During the Albian, carbonate deposition developed along the eastern margins of the basin. Subsequent detachment and basinward rafting of the carbonate platform over the salt layer, combined with further thermal collapse, created a deepwater sedimentation regime through the Late Cretaceous.
The Late Cretaceous also saw a change to clastic-dominated sedimentation strongly influenced by salt movements. During major Cenomanian and Turonian lowstands, coarser clastic sediments were fluxed into more distal parts of the basin to accumulate in local salt-withdrawal depocenters. Following the main thermal collapse of the basin, Tertiary deposition continued under deepwater conditions and continuing salt withdrawal. During this last phase of basin fill, gravity-flow processes associated with widespread channel and terminal fan systems dominated the sedimentation.
Postdepositional flow of the salt has been the main structure-producing process in the basin. At the periphery of the basin, migration of mobile salt has occurred to a cumulative thickness of up to 2.5 miles (4 km). In some basinal areas, salt withdrawal has been sufficiently dramatic to allow Miocene sediments to touch down on residual Albian or Aptian carbonates and evaporites, thereby creating potential migration pathways through the salt layer.
Source rocks and maturation
Four potential source formations for oil are recognized in the Kwanza Basin:
• postsalt - Upper Cretaceous marine shales, Albian (and some Aptian) micritic shales; and
• presalt - Aptian lacustrine and marginal marine evaporitic shales, Barremian-Neocomian lacustrine shales.
Where present, the presalt Neocomian to Aptian sources are mature for hydrocarbon generation. They display Type I to II kerogen characteristics with average total organic carbon (TOC) contents of less than 2% and hydrogen index (HI) values of 300 to 800. Albian and Aptian micritic shales are believed to be developed regionally and are mature for oil generation in the deeper parts of the basin. These formations show Type II kerogen characteristics with TOC up to 6% and HI up to 600. Upper Cretaceous source formations can be mature for oil generation in the deeper salt-withdrawal troughs. Typically, these shales have TOC less than 4% and HI more than 500.
Reservoirs and seals
Reservoirs are present at all levels of the stratigraphic section in the Kwanza Basin. The most attractive reservoir targets are Tertiary and Upper Cretaceous deepwater, gravity-flow sandstones. Having been deposited in a generally shale-prone environment, top and side seals are not a problem for these reservoirs. Hydrocarbons can, however, migrate to the porous layers through a network of penetrative faults or through a series of vertically connected sand bodies.
Tertiary sand reservoirs are known to be productive in the adjacent Lower Congo Basin and have excellent poroperm qualities. Their acoustic impedance characteristics facilitate their identification on seismic data and enable recognition of their wide spatial and stratigraphic distribution. Typically they display meandering and cross-cutting channel geometries together with lateral splays and terminal lobes or fans. Cretaceous sand reservoirs are more vertically restricted than those in the Tertiary, but well studies have demonstrated the occurrence of significant clastic input during the Cenomanian and Turonian corresponding with the lowstand episodes from 94 million and 90 million years ago. Seismic mapping has shown that these surfaces are associated with reflection characteristics indicative of porous facies development. These potential reservoirs remain untested, but deepwater Cenomanian sandstones are known to be productive in Lower Congo Block 4. Similarly aged shallowwater mixed clastic-carbonate reservoirs also are productive in coastal areas.
Immediately above the salt are several Aptian and Albian carbonate facies reservoirs of variable quality. Typically, wells in the shallow offshore have encountered Late Albian chalky and micritic Quissonde facies reservoirs within closure below Cenomanian shale top seals. However, due to lateral facies transition, more productive reservoirs can be found in the deeper tracts of the basin where Aptian Binga facies carbonate grainstones can be sealed by overlying early Albian mudstones. In the deeper presalt section, continental and lacustrine sandstones interbedded with seal and source facies shales offer some reservoir potential, although their depth of burial can have a limiting effect on their poroperm qualities.
Trapping styles
The basin displays a variety of trapping styles within the postsalt section:
• conventional drape anticlines over salt;
• salt-induced turtleback anticlines;
• fault-bounded traps in inversion structures;
• stratigraphic traps in channel-fill and lobe/fan sediments; and
• truncation traps below unconformities.
A 3-D survey area over the Kwanza ultradeep block indicates more than 40 four-way, salt-supported, dip-closed structures with a relief greater than 820 ft (250 m) and areal extents up to 115 sq miles (300 sq km). Many of these structures have associated direct hydrocarbon indicator (DHI) amplitude anomalies in the Tertiary and Upper Cretaceous section, which significantly enhance their prospectivity. Many of the adjacent synclines allow sufficient burial of Albian source rocks to oil-generative levels of maturity and, therefore, provide efficient migration paths into the potential traps. A typical section from the 3-D area shows salt-supported anticlines and potential stratigraphic traps with associated amplitude anomalies (Figure 1).
Combination anticlinal and unconformity geometries from the southern part of the basin are illustrated in Figure 2.
Regional considerations and interpretation based on recent 2-D and 3-D seismic data have established that significant petroleum potential exists in the Kwanza Basin comparable with that of the adjacent Lower Congo Basin. Of particular importance are:
• a recent oil discovery that establishes an effective petroleum system;
• the presence of a significant number of salt-induced trap geometries;
• the direct seismic identification of reservoir facies;
• the recognition of DHIs indicative of active petroleum systems throughout the area; and
• the early licensing of open areas this year.
WesternGeco has acquired an extensive seismic database over the Kwanza Basin with which to assess the potential of this vast area, including some 6,200 miles (10,000 km) of 2-D and 6,500 sq mi (17,000 sq km) of 3-D coverage, mostly of recent vintage. Additional 3-D surveys are being planned.
Acknowledgements
The author thanks all colleagues at WesternGeco who assisted in this interpretation study and the WesternGeco Multiclient Department for permission to publish this article. Dr. Bob Goldhammer, University of Texas, also provided valuable collaboration.