Petroleum Potential of the Congo Basin - Geology and Resource Potential of the Congo Basin - page 363

in the Kalemie area. This loosely constrains an important
compressional basin inversion event that Daly et al. ( 1992 )
related to far-field effects of the Late Permian—Triassic
development of the Cape Fold Belt inSouth Africa (Halbich
et al. 1983 ; Le Roux 1995 ; Delvaux 2001 ; Newton et al.
2006 ; Tankard et al. 2009 ).
The lateral facies changes across the basinmake correlation
between the different stratigraphic packages difficult. This is
particularly the case for the pre-Jurassic successions (ca.3 km
thick) encountered in the Mbandaka-1 and Gilson-1 wells
above the Neoproterozoic carbonates. As a consequence, strat-
igraphic correlations of the Paleozoic to Triassic sequences of
the CB (Daly et al. 1992 ;ECL 1988 ;ESSOZaire 1981a , b ;
Kadima et al. 2011a and other unpublished reports; Linol et al.,
Chap. 7 , this Topic) differ each other. This is mainly caused by
the lack of chronostratigraphic control for this large part of the
basin fill. By contrast, the age of the overlying Jurassic to
Neogene sequences and the underlying Neoproterozoic
carbonates are better constrained.

geochemical analyses (Total Organic Carbon (C org ), Rock-
Eval and Gas Chromatography - Mass Spectrometry) were
undertaken by Sachse et al. ( 2012 ) on a large number of
Palaeozoic and Mesozoic outcrop and core samples from
the Dekese and Samba wells. The JNOC Rock-Eval results
are reported in Table 18.1 . The analysis of the RMCA
samples [RWTH data of Sachse et al. ( 2012 ) and two
data from Kadima ( 2007 )] are reported in Table 18.2 . The
results, averaged for each stratigraphic unit, are given in
Table 18.3 .
The type of kerogen in the sediment is characterized
using the Rock-Eval results on a Van-Krevelen equivalent
diagram (Espitalie et al 1977 ), by the Hydrogen Index (mg
HC equivalents/g C org ) and Oxygen Index (mg CO2/g C org ).
On such diagram (Fig. 18.3 ) different kerogen types are
shown to follow different evolution paths depending on
thermal maturation. Progressive decrease in Hydrogen and
Oxygen index values reflects loss of hydrocarbon chains and
oxygenated functions (Tissot and Welte 1978 ). Kerogen
type I is typical lacustrine organic-matter, rich in aliphatic
chains and poor in aromatics, derived from algal lipids, or
enriched by microbial activity. Kerogen type II is richer in
aromatics, which is usually attributed to marine organic
matter deposited in a reducing environment, but which can
also correspond to a combination lacustrine algae (type I)
and terrestrial (type III) organic matter. Kerogen type III is
rich in aromatics and oxygenated functions and is derived
from terrestrial higher plants. Organic matter unable to
generate oil or gas is qualified as Type IV kerogen. Results
of the RMCA samples analyzed by RWTH Aachen (Sachse
et al. 2012 ), with two samples of Kipala shales from Kadima
( 2007 ) are shown in Fig. 18.3a , and the JNOC samples
(JNOC 1984 ), in Fig. 18.3b . Sachse et al. ( 2012 ) further
studied the organic matter by organic petrology and
molecular organic geochemistry. Combined with the total
organic matter content (C org ) and Rock-Eval parameters, this
allowed the following characterization of

18.4 Potential Source Rocks

Several potential source rocks have been recognised in the
CB at different stratigraphic levels and locations, but with
relatively limited lateral continuity (at the scale of the basin).
These are listed below, together with their age estimations:
￿ Mamungi

greyshales of the Lokoma Group

(Neoproterozoic)
￿ Alolo dark shales of the Aruwimi Group in the Aruwimi
River region north of Kisangani (Early to Middle

Paleozoic)
￿ Lukuga peri-glacial grey-shales in the Dekese well, and
post-glacial coal measures in the Kalemie and Upemba
coal fields, respectively, along Lake Tanganyika and in
the Kibara Belt in North-Katanga (Late Carboniferous-
Permian);
￿ Stanleyville Group with black shales along the Congo
River upstream Kisangani (Lualaba) but red sand and
siltstones in the Samba well (Middle or Upper Jurassic);
￿ Loia Group with seven thin lacustrine black shales levels
in the Samba well;
￿ Kipala black shales south of the Kasai River (Upper
Cretaceous, Kwango Group).
The petroleum potential and maturation estimates of
these source rocks were initially based on a limited number
of organic matter analyses from a selection of samples of
core and outcrops, stored at the RMCA. First generation of
Rock-Eval instruments (RRI 1988 ) were used for the
analyses. JNOC ( 1984 ) also performed a number of analyses
on separate outcrop samples, mainly from the Loia and
Stanleyville organic-rich shales, but we were not able to
re-locate the samples on maps. New petrological and

the different

source rock horizons (Table 18.3 ):
￿ Samples of the Alolo shales from the Aruwimi Group are
in general very low in C org ( 0.2 % in average), and

contain a high amount of degraded organic matter. They
are considered barren. Samples from the Yambuya sec-
tion are slightly richer (0.58 % in average) but few of
them are rich enough to allow Rock-Eval analysis; which
in any case released very little quantities of hydrocarbon
during pyrolysis, but high quantities of CO 2 (very low HI
and high OI). They contain a type III/IV kerogen and
cannot be considered as a potential source rock. Simi-
larly, an Alolo shale sample taken during the 2011
CoMiCo-RMCA field survey is almost devoid of organic
matter (0.08 % C org. ; Harriman 2012 ), showing that oxi-
dation of the organic matter during the 60 years storage
cannot be invoked to explain these low values.

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