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The AAPG/Datapages Combined Publications Database
Houston Geological Society Bulletin
Abstract
POSTER SESSION
Abstract: Petroleum Geology of
Block
2, Offshore Congo Basin, Angola
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By
1Texaco Angola Inc., Luanda, Angola
2Sonangol, Luanda, Angola
The major basins of Angola include the
oil producing Congo and Kwanza Basins
and the non-producing Benguela and
Namibe Basins. Block
2 is located within
the offshore portion of the Congo Basin
which extends southwards from the
Cabinda area to the Precambrian Ambrizete
Spur, a basement high that marks the
boundary between the Congo Basin and
the Kwanza Basin. Dolomitized Albian-age
Pinda formation carbonates are the primary
reservoirs within
Block
2. Tertiary (Eocene
and Oligocene) turbidite sands are also
locally oil-bearing on
Block
2.
Northwards trending listric and antithetic
faulting has resulted in a variety of oil-trap
ping structures including simple rollovers
and horst blocks. Salt rafting and down-to-the-basin (westwards) gravity sliding of
Pinda "rafts" has resulted in a number of
oil fields consisting of separated blocks of Pinda
carbonate with variable oil-water
contacts. Texaco (operator) and its partners, Sonangol, Braspetro and Total have
recorded 3D seismic over all of the fields
in Block
2 in order to optimize management
of the Pinda and Tertiary reservoirs.
Extensive core coverage has been
obtained to develop a full understanding of
the depositional environment and reservoir
characteristics of the Pinda reservoirs.
Lombo East is an example of a Block
2
field producing from the Pinda formation.
This field has produced over 80 million
barrels of 40 degree API crude since its
discovery in 1984. The Lombo East "raft"
has a closure of 1600 acres, vertical relief
of 250 meters and an oil column of 130
meters. The reservoir is a high-energy
shoal facies with vugular porosity ranging
between 15 and 20%. The Essungo fled is the only field on
Block
2 which produces
from the Tertiary. Essungo was discovered in 1975 and has produced 30 million
barrels of oil to date. Sand deposition is
interpreted to have occurred in a deep
water environment. The average porosities within the field range from 16 to 22%
and oil gravities vary between 32 and 39
degrees API.
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