Original Article
Characterization of organic
matter from a stratigraphic
sequence intercepted by the
Nemo-1X well, Mozambique:
Potential for hydrocarbon
generation
Energy Exploration & Exploitation
0(0) 1–15
! The Author(s) 2018
DOI: 10.1177/0144598717753920
journals.sagepub.com/home/eea
Agostinho Mussa1, Deolinda Flores2,
Joana Ribeiro2, Ana MP Mizusaki1,
Mónica Chamussa3, Jo~
ao GM Filho4 and
Wolfgang D Kalkreuth1
Abstract
The Mozambique Basin, which occurs onshore and offshore in the central and southern parts of
Mozambique, contains a thick sequence of volcanic and sedimentary rocks that range in age from
the Jurassic to Cenozoic. This basin, along with the Rovuma basin to the north, has been the main
target for hydrocarbon exploration; however, published data on hydrocarbon occurrences do not
exist. In this context, the present study aims to contribute to the understanding of the nature of
the organic matter of a sedimentary sequence intercepted by the Nemo-1X exploration well
located in the offshore area of the Mozambique Basin. The well reached a depth of 4127 m, and
33 samples were collected from a depth of 2219–3676 m ranging in age from early to Late
Cretaceous. In this study, petrographic and geochemical analytical methods were applied to
assess the level of vitrinite reflectance and the organic matter type as well as the total organic
1
Curso de Pós-Graduaç~ao em Geociências, Instituto de Geociências, Universidade Federal do Rio Grande do Sul, Porto
Alegre, Brazil
2
Departamento de Geociências, Ambiente e Ordenamento do Território, Faculdade de Ciências da Universidade do
Porto, Instituto de Ciências da Terra, Polo da Universidade do Porto, Porto, Portugal
3
National Hydrocarbons Company (ENH), Maputo, Mozambique
4
Departamento de Geologia, Laboratório de Palinofácies & Fácies Orgânica (LAFO), Instituto de Geociências,
Universidade Federal do Rio de Janeiro, Rio de Janeiro, Brazil
Corresponding author:
Agostinho Mussa, Curso de Pós-Graduaç~ao em Geociências, Instituto de Geociências, Universidade Federal do Rio
Grande do Sul, Avenida Bento Gonçalves 9500, Porto Alegre, RS 91509-970, Brazil.
Email: agostinhomussa@gmail.com
Creative Commons CC BY: This article is distributed under the terms of the Creative Commons
Attribution 4.0 License (http://www.creativecommons.org/licenses/by/4.0/) which permits any use,
reproduction and distribution of the work without further permission provided the original work is attributed as specified
on the SAGE and Open Access pages (https://us.sagepub.com/en-us/nam/open-access-at-sage).
2
Energy Exploration & Exploitation 0(0)
carbon, total sulfur, and CaCO3 contents. The results show that the total organic carbon content
ranges from 0.41 to 1.34 wt%, with the highest values determined in the samples from the Lower
Domo Shale and Sena Formations, which may be related to the presence of the solid bitumens
that occur in the carbonate fraction of those samples. The vitrinite random reflectances range
from 0.65 to 0.86%Rrandom, suggesting that the organic matter in all of the samples is in the peak
phase of the “oil generation window” (0.65–0.9%Rrandom). The organic matter is mainly composed of vitrinite and inertinite macerals, with a minor contribution of sporinite from the liptinite
group, which is typical of kerogen type III. Although all of the samples have vitrinite reflectances
corresponding to the oil window, the formation of liquid hydrocarbons is rather limited because
the organic matter is dominated by gas-prone kerogen type III.
Keywords
Mozambique Basin, exploration well Nemo-1X, vitrinite reflectance, solid bitumen, kerogen type,
hydrocarbon generation potential
Introduction
Mozambique, as an emerging African country is currently undertaking intense research and
exploration of its natural resources, especially for hydrocarbons. Of the six major sedimentary basins in Mozambique (Figure 1) this activity is focused on two large basins: the
Mozambique Basin in the central and southern part of the country and the Rovuma
Basin in the north (Figure 1).
A general discussion on the hydrocarbon potential of the Mozambique Basin was published by Alan et al. (1991) and Iliffe et al. (1991). They used Royden’s model to determine
the maturation and concluded that a source rock which reaches maturity for hydrocarbon
generation likely lies somewhere within the Lower Cretaceous or Jurassic strata. The probability of such a source rock being present is enhanced by the high marine/terrigenous shale
depositional setting envisaged for these strata.
The reservoirs may be present in Cretaceous rocks and regardless of the model used or
the heat flow history configuration applied, the basin is expected to have mature hydrocarbon source rocks in the eastern part at depths of 3000–4000 m. The ideal situation of the
relative timing of source deposition followed by faulting, seal deposition, and maturation of
the source rocks seems to be the case in the South Mozambique Graben (Alan et al., 1991;
Iliffe et al., 1991).
According to Michael (2016), the Mozambique Coastal Province contained only five
gas accumulations exceeding the minimum size of 30 billion cubic feet of gas. This province is considered to be underexplored on the basis of its level of exploration activity.
Using a geology-based assessment, the United States Geological Survey (USGS) estimated
mean volumes of undiscovered, technically recoverable conventional oil and gas resources
for the Mesozoic–Cenozoic Reservoirs Assessment Unit in the Mozambique Coastal
Province. The mean volumes are estimated at 11.682 million barrels of oil, 182.349 billion
cubic feet of gas, and 5.645 million barrels of natural gas liquids. The estimated mean size
of the largest oil field that is expected to be discovered is 1.041 million barrels of oil and
the estimated mean size of the expected largest gas field is 7.976 billion cubic feet of gas.
Mussa et al.
3
Figure 1. Map showing the six sedimentary basins of Mozambique (ECL, 2000) and the Nemo-1X well
location investigated in the present study.
For this assessment, a minimum undiscovered field size of 5 million barrels of oil equivalent was used by Michael (2016).
Published data on the hydrocarbon generation potential in the sedimentary basins of
Mozambique are virtually nonexistent, and data are restricted to internal company reports
(ECL, 2000; Lineback et al., 1986; Salman et al., 1990).
In the Mozambique Basin previous geochemical studies on the Nemo-1X well (Lineback
et al., 1986) indicated the predominance of kerogen type III suggesting a continental depositional environment. This study also showed that based on vitrinite reflectances the thermal
maturity of the organic matter in well Nemo-1X ranges from immature to the peak oil
generation window.
However, relatively low hydrogen indexes as determined by Rock-Eval Pyrolysis suggest
that hydrocarbon generation is restricted to gas generation potential in samples analyzed
from the Cretaceous Lower Domo Shale Formation (Lineback et al., 1986).
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Energy Exploration & Exploitation 0(0)
The main objective of the present study is to add more information on the petrographic
and geochemical characteristics of samples collected from the Nemo-1X well (Figure 1) and
as such aid in the evaluation of the hydrocarbon generative potential of the Mozambique
Basin.
The samples were analyzed using analytical methods of organic petrography and geochemistry. The role of organic petroleum in the exploration of conventional and unconventional hydrocarbon systems was recently reviewed by Hackley and Cardott (2016) and
Suárez-Ruiz and Mendonc¸a Filho (2017), including the delineation of organic maturity
and the evaluation of organic facies.
In the present study, the petrographic analyses included vitrinite reflectance to assess the
maturity of the studied sequence and to identify the petrographic composition, whereas the
geochemical analyses included a determination of the total organic carbon (TOC), total
sulfur (TS), and CaCO3 contents.
Geological setting
The Mozambique Basin occupies the central and southern parts of Mozambique, extending
onto the continental shelf and slope (Figure 1). The sedimentary fill is composed of Upper
Jurassic, Cretaceous, and Cenozoic rocks which overlie “Karoo” volcanics. It covers an area
of approximately 500,000 km2, of which 275,000 km2 are onshore and 225,000 km2 offshore
to the 2000 m isobaths (ECL, 2000). The basin forms a large asymmetric depression,
inclined eastward and flanked by crystalline Pre-Cambrian basement or by the Karoo
basalts (Salman et al., 1990).
The peculiarities of the tectonic structure are determined by the relationship between the
several phases of structural development:
• the Mozambique Basin is part of the East African continental margin system, whose
formation can be traced from the Late Jurassic/Early Cretaceous;
• the structures of the basin overlie the more ancient structural elements of the
Gondwanaland intracratonic trough and the Karoo grabens;
• the pericontinental depression overlies the rift structures of the early riftogenic stage
(Late Jurassic/Early Cretaceous);
• the basin is located at the southern end of the East African Rift, which is dated as neoriftogenic stage (Late Cretaceous–Cenozoic) (Salman et al., 1990).
The following structural stages have been identified in the tectonic structure of the
Mozambique Basin, reflecting the main stages in the geological history of the basin:
• pre-Cambrian crystalline basement; Gondwana structural stage (Karoo) and postGondwana stage (Upper Jurassic Cenozoic) (Salman et al., 1990).
The stratigraphic sequence of the basin (Figure 2) is comprised of Cenozoic, Cretaceous, and
Upper Jurassic sedimentary rocks, as well as igneous rocks of the Karoo (Salman and Abdula,
1995).
Mussa et al.
5
Figure 2. General stratigraphy of the Jurassic to Tertiary strata of the Mozambique Basin (ECL, 2000).
Stratigraphically (from bottom to top), the Mozambique Basin has the following geological formations (Figure 2): Red Beds, Lupata, Maputo, Sena, Lower Domo Shale, Domo
Sand, Upper Domo Shale, Lower Grudja, Upper Grudja, Cheringoma, Zambezi Deltaic
Complex, Inharrime, Temane, Jofane (ECL, 2000). Lithologies and depositional environments of these formations are discussed briefly below based on studies by ECL (2000),
Salman and Abdula (1995), and Salman et al. (1990).
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Energy Exploration & Exploitation 0(0)
The basal Red Beds Formation (Figure 2) represents the initial flooding of the shelf in the
Late Jurassic and subsequent deposition of the first true drift deposits. The top of this
sequence is represented by the “brown” horizon designated as the “Mid-Cretaceous
Unconformity” which in the Zambezi Depression marks the transition from the Lupata
Formation to the Lower Domo Shale (ECL, 2000).
The Lupata Formation (Figure 2) is developed in the NW part of the basin within the
limits of the Zambezi Graben. This section is an eroded basalt surface and it comprises
multicolored conglomerates and sandstones with large gneiss and Karoo rock fragments.
These sediments are interbedded with rhyolite lavas.
The total thickness of this sequence is about 150–200 m, the age of the Lupata Formation
defined by K/Ar method ranges from 166 to 106 MA. It was thus deposited between the end
of the Middle Jurassic and the Early Cretaceous (Salman et al., 1990).
Maputo Formation (Figure 2) is distributed in the southern and central areas of the
Mozambique Basin and occurs as a layer of Glauconitic-quartzose sandstone and arenaceous limestone, interbedded with argillites. Sandstone of the Maputo Formation is deposited on eroded Stromber Basalts or on the Red Beds. The most recent dating of the Maputo
Formation suggests that it is of Neocomian stage (Salman et al., 1990).
The Sena Formation (Figure 2) is predominated by arkosic sandstone, pebble, and conglomerate lithologies, representing continental and deltaic sediments.
The Lower Domo Shale Formation (Figure 2) is a thick sequence consisting of darkcolored shale with occasional sandstone interbeds. It is the marine equivalent to the Sena
Formation and can be correlated across a lateral facies change.
The sediments of Lower Domo Shale Formation provide a regional cap rock for the
reservoirs, and in addition, the thick shale sequence is regarded as the main source for
hydrocarbon generation within the Mozambique Basin, with source rock properties improving toward the east (Salman et al., 1990).
The Domo Sand Formation (Figure 2) comprises interbedded quartzose and glauconiticquartzose sandstone with shale. The sands were deposited within a narrow near-shore zone
in a shallow-water shelf environment, which gradually transgressed in a westerly direction.
In the east a deeper water environment existed, and in this area the sandstones are thinner
and the formation becomes progressively more shaley eastwards (Salman et al., 1990).
The Upper Domo Shale Formation (Figure 2) is characterized by the occurrence of
continental clay sands and sandstone. The distribution of the Upper Domo sands and
facies relationship within this interval is typical of a transgressive marine sequence. The
most favorable conditions for forming sandstones with good reservoir properties are related
to the shallow-water shelf zone developed in the southwestern and southern areas of the
Zambezi Block (Salman et al., 1990).
The Lower Grudja Fm. (Figure 2) consists of dark gray shale interbedded with beds of
glauconitic sandstones originally deposited over the whole basin. This sequence was formed
in a shallow-water shelf environment (Salman et al., 1990).
The Upper Grudja Fm. (Figure 2) is a sequence of glauconitic sands, clays, and marls
interlayered with bands of limestone (Salman et al., 1990). The Upper Grudja Formation
was deposited at a time of transgression and highstand and decreasing siliciclastic input in
the Early Paleocene. The total thickness of the formation is 300–400 m (Salman and Abdula,
1995). The formation was deposited in an entirely subaqueous, low-energy offshore marine
environment which appears to have occurred over a large area (ECL, 2000).
Mussa et al.
7
The Cheringoma Formation (Figure 2) (Middle–Upper Eocene) comprised of limestone
with bands of clays and calcareous sandstones. The thickness of the formation is 250 m.
Limestone is widespread in the western areas of the Mozambique Basin and were deposited
on an unconformity (Salman et al., 1990).
The Zambezi Deltaic Complex (Figure 2) is the largest Cenozoic deltaic complex along
the East African coast. The complex consists of Oligocene to recent sediments and exhibits a
total thickness of 4000 m. The strata of the Zambezi Deltaic Complex comprise an intercalation of conglomerates, sandstone, and shale with typical deltaic bedding and numerous
interfacies hiatuses and ancient erosional canyons (Salman et al., 1990).
Strata of the Inharrime Formation (Figure 2) comprise a sequence of red dolomites, red
clays, and sandstones with bands of anhydrite. The Formation thickness is 100–300 m.
These sediments were deposited in a restricted lagoonal environment (Salman et al., 1990).
Strata of the Temane Formation (Figure 2) consist of interbedded anhydrite, red clays,
and sandstones, which were formed within the central part of a brackish-water lagoon. The
Temane anhydrites occupy the central part of the basin and are similar in age to Inharrime
beds. The thickness of the formation is up to 110 m.
Strata of the Jofane Formation (Figure 2) occur primarily as marine carbonate facies
such as limestone, calcarenite, and arenaceous limestone, attaining a thickness of up to 200
m (Salman et al., 1990).
Tertiary sediments are represented both by shallow-water shelf and deeper-water continental slope deposition. Within the shallow-water shelf area the tertiary sediments are
stratigraphically and lithologically subdivided in the following formations: Upper Grudja,
Cheringoma, Inharrime, Temane, and Jofane.
Well location, sampling, sample preparation, and analytical methods
Well location and sampling
The Nemo-1X well is located offshore central Mozambique (Figure 1) with a depth of 4127
m. The well intercepted (from top to bottom) the following formations (Figure 2), which
ranged in age from the Eocene to Early Cretaceous: the Cheringoma and Deltaic complex,
Upper Grudja, Lower Grudja, Upper Domo Shale, Domo Sand, Lower Domo Shale, Sena,
and volcanic agglomerates.
The samples were collected by the first author at the National Hydrocarbon Company
Mozambique (ENH) in form of dry and nonwashed cuttings.
A total of 33 samples (cuttings) were collected from four stratigraphic intervals (Table 1),
the Upper Domo Shale, Domo Sand, Lower Domo Shale, and Sena Formations (Table 1),
and were submitted to petrographic and geochemical analyses.
Sample preparation
The sample preparation included cleaning the cuttings with dichloromethane to remove
impurities from drilling, as they were collected dry and not washed prior to preparation
for geochemical analysis. Grain size for chemical analyses was <250 mm, whereas grain size
for petrographic analysis was approximately 2 mm.
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Energy Exploration & Exploitation 0(0)
Table 1. Sample identification, vitrinite random reflectances (%Rrandom), total organic carbon (TOC)
(wt%), total sulfur (TS) (wt%), TOC/TS ratios, and CaCO3(%) contents of the studied samples.
Sample
number
Depth
(m)
Rrandom
(%)
TOC
(wt%)
Total sulfur
(wt%)
TOC/TS
CaCO3
(wt%)
Upper Domo Shale
1
2
3
4
5
6
7
8
9
10
11
2219
2310
2402
2496
2588
2682
2713
2769
2794
2816
2865
0.74
0.73
0.65
0.67
0.68
0.68
0.71
0.69
0.68
0.69
0.66
0.43
0.52
0.51
0.67
0.63
0.56
0.60
0.69
0.70
0.67
0.74
0.42
0.38
0.28
0.36
0.34
0.45
0.56
0.21
0.29
0.43
0.48
1.02
1.37
1.82
1.87
1.88
1.25
1.08
3.25
2.44
1.55
1.56
21
21
21
22
29
25
25
25
26
27
27
Domo Sand
12
13
2915
3002
0.70
0.72
0.58
0.50
0.28
0.24
2.07
2.06
28
25
Lower Domo Shale
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
3050
3127
3167
3197
3234
3277
3295
3338
3362
3380
3399
3426
3457
3490
3522
3554
0.67
0.68
0.69
0.73
0.69
0.73
0.79
0.71
0.76
0.71
0.70
0.87
0.66
0.75
0.73
0.74
0.41
0.56
0.68
0.79
1.14
0.89
0.89
1.06
0.84
0.89
0.99
0.96
0.71
1.34
1.14
0.96
0.24
0.26
0.38
0.26
0.50
0.45
0.34
0.38
0.33
0.43
0.39
0.39
0.41
0.44
0.33
0.40
1.70
2.18
1.82
3.03
2.27
1.99
2.58
2.76
2.58
2.08
2.55
2.46
1.75
3.04
3.45
2.42
21
21
24
25
26
35
32
32
36
34
32
35
32
36
31
40
Sena
30
31
32
33
3578
3615
3646
3676
0.69
0.71
0.71
0.86
0.85
1.09
0.88
0.84
0.32
0.46
0.47
0.43
2.62
2.37
1.88
1.94
32
31
36
21
Formation
Geochemical analyses (TOC, TS, and CaCO3)
The samples were pulverized (<80 mesh) and 1 g of the pulverized sample was submitted to
the TOC analysis. Prior to the analyses the samples were subjected to chemical treatment to
eliminate the inorganic carbonate fraction according to the following methodology:
Step 1: About 0.26 g of the sample previously pulverized was weighed into a filter porcelain
crucible (of known mass). After weighing, the samples were acidified with hydrochloric acid
(HCl) during 24 h to remove the carbonates present;
Mussa et al.
9
Step 2: The samples were washed with hot distilled water for 1 h to remove the chlorides.
The samples were then washed with distilled water at room temperature until the pH was
near 6, and finally, the excess water was drained.
Step 3: Samples were placed in an oven at 65 C for approximately 3 h for drying. After
cooling, the crucibles were weighed again.
After the acidification process, for TOC and TS determinations, all the samples were
analyzed using a LECO SC144 analyzer. The equipment was calibrated using standard
samples before and after the analyses. A muffle furnace that reaches temperatures of
1350 C was used for the analyses, leading to complete combustion of the sample. The
equipment records the concentrations in CO2 and SO2 gases, the result being expressed as
a percentage of mass.
The carbonate (CaCO3) content was determined by the following equation
Carbonatesð%Þ ¼ 100 IR
where IR corresponds to the fraction of the sample that is not eliminated by the acid
treatment, assuming that the entire carbonate fraction was eliminated.
The IR was calculated using
IR ¼ ðDM=TMÞ 100
where DM is the mass after the chemical treatment, and TM is the initial mass of the sample
before the chemical treatment. The result is expressed in weight percentage.
Petrographic analyses
Polished blocks of whole rock samples for petrographic observations were prepared according
to American Society for Testing and Materials (ASTM) D2797 (2011) standard.
The mean random reflectance (%Rrandom) was measured on vitrinite and on solid
bitumen according to ASTM D2797/D2797M11 (2011) and ASTM D7708-14 (2014)
using a LEICA DM 4000M microscope equipped with a 50X oil immersion objective.
A Discus-Fossil software was used to determine the vitrinite reflectances. The microscope
was calibrated using a YAG standard (0.903%Rrandom) and an optical black (zero) glass.
The identification and characterization of the organic matter were made according to the
internationally proposed TSOP-ICCP Dispersed Organic Matter Classification (Stasiuk et
al., 2002), using both reflected white light and incident blue light (fluorescence) illumination.
The solid bitumens were classified according to Jacob (1989).
Results
The results of the geochemical and petrographic analyses of the samples are listed in Table 1.
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Energy Exploration & Exploitation 0(0)
TOC, TS, and CaCO3 contents
TOC content. The TOC values in the samples from well Nemox-1X range from 0.41 to 1.34
wt% (Table 1), gradually increasing with depth, most likely related to slightly higher accumulation and preservation rates in samples taken from greater depths.
The Upper Domo Shale and Domo Sand formations have TOC contents between 0.43
and 0.74 wt% (Table 1, Figure 3), with the majority of samples having contents between 0.5
and 1.0 wt%. According to Peters and Cassa (1994) these samples have a fair hydrocarbon
generation potential.
The highest values were found in the samples from the Lower Domo Shale and Sena
Formations, where most of the samples have TOC values between 0.5 and 1.5 wt% (Table 1,
Figure 3). According to Peters and Cassa (1994) this group of samples has a fair-to-good
hydrocarbon generation potential. Considering these criteria, the samples with the best hydrocarbon generation potential are from the Lower Domo Shale and Sena Formations, confirming
that as suggested by Salman et al. (1990), the strata of the Lower Domo Shale Formation are
the main source rocks for hydrocarbon generation within the Mozambique Basin.
TS content.
The TS content is considered to give an indication of the physicochemical conditions (oxidation
versus reduction) of the depositional environment (Tissot and Welte, 1984).
Figure 3. Depth variations of vitrinite reflectances, TOC, and CaCO3 contents and the TOC/TS ratios in
the Nemo-1X well. Hydrocarbon generation potential based on TOC contents: P (poor) ¼ TOC< 0.5 wt%;
F(fair)=TOC 0.5–1.0 wt%; G (good) ¼TOC 1.0–2.0 wt%, from Peters and Cassa (1994).
TOC: total organic carbon; TS: total sulfur.
Mussa et al.
11
Microscopic analyses showed the abundance of pyrite in the samples and it is suggested
that the majority of the sulfur determined by chemical analysis comes from source.
The TS contents determined for the Nemo-1X well samples were relatively low and did
not exceed 0.56 wt% (Table 1).
TOC/TS ratios. The majority of samples analyzed from the Upper Domo Shale, Domo Sand,
Lower Domo Shale, and Sena Formations have TOC/TS ratios less than 3 (Table 1), which
according to studies by Berner (1995) and Borrego et al. (1998) indicate a reducing depositional environment.
CaCO3 content. The sequence analyzed is essentially siliciclastic with relatively high carbonate
contents in certain intervals. The CaCO3 content is minor in the Upper Domo Shale and
Domo Sand formations, with values ranging between 20 and 30%, whereas in the Lower
Domo Shale and Sena Formations the CaCO3 contents increase gradually with depth reaching up to 40% (Figure 3). The increase of the CaCO3 content in these formations is associated with the presence of solid bitumen, which may suggest a preferential precipitation of
the bitumen within the carbonate fraction.
Petrographic composition
According to the petrographic analysis, the dispersed organic matter identified in the samples is essentially comprised of macerals of the vitrinite and inertinite groups, with particle
sizes varying between 5 and 50 mm (Figure 4(a) to (c)), corresponding to gelified preserved
tissues from higher plants, occasionally preserving the botanical structure. Macerals of the
liptinite group, identified using blue light excitation, are very rarely observed (Figure 4(d))
and were identified as sporinite.
In some samples of the Lower Domo Shale and Sena Formations, two families of solid
bitumen (Figure 4(e) and (f)) denominated B1 family and B2 family were observed in the
intercrystalline void spaces of the mineral matter essentially associated with carbonates.
Their shapes varied according to the pore shapes where they occurred and exhibited optically isotropic homogeneous properties. The B1 family had reflectances between 1.5 and
2.0%Rrandom, and the other family (B2) had reflectances between 2.1 and 2.6%Rrandom
(Figure 5). According to Jacob (1989), the bitumen families were classified as epi-impsonite
(family B1) and meso-impsonite (family B2), respectively.
Numerous occurrences of dispersed, low maturity migrabitumen such as albertite, gilsonite, and wurtzilite may indicate the occurrence of petroleum, whereas high maturity
dispersed migrabitumen such as impsonite, usually imply that no petroleum can be expected
(Jacob, 1989). If suitable trap structures are present, natural gas or condensate can be
associated with the occurrences of the high maturity migrabitumen.
Throughout the sequence, some bioclasts (Figure 4(g)) corresponding to fragments of
fossil shells and significant quantities of framboidal syngenetic pyrite (Figure 4(h)) were also
observed.
In general, the organic matter identified in the Nemo-1X well represented kerogen type
III, as indicated by the predominance of vitrinite and inertinite macerals.
Vitrinite macerals originate from land plants and mature along the type III kerogen
pathway (Peters and Cassa, 1994). These macerals are considered to be derived from a
terrestrial source and are gas-prone constituents. In the Mozambique Basin the organic
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Energy Exploration & Exploitation 0(0)
Figure 4. Photomicrographs of organic particles observed in samples from the Nemo-1X well: (a) Vitrinite
fragments associated with mineral matter, sample 16, depth 3167 m, Lower Domo Shale Formation,
micrograph taken in reflected white light illumination; (b) vitrinite fragments associated with mineral matter,
(continued)
Mussa et al.
13
Figure 5. Histogram of the solid bitumen reflectances (B1 and B2) of sample 19, depth 3277 m.
matter derived from a terrestrial source was deposited in a suboxic environment suitable for
its preservation, which is in accordance with the presence of framboidal syngenetic pyrite in
all of the analyzed samples. The presence of solid bitumen suggested that some hydrocarbon
migration occurred (Jacob, 1989).
Vitrinite random reflectance (%Rrandom). The vitrinite random reflectances determined from the
Nemo-1X well samples ranged from 0.65 to 0.86%Rrandom (Table 1), which places all of
the samples within the peak oil window (0.65–0.90%Rrandom) as defined by Peters and
Cassa (1994). The vitrinite reflectances show a slight increasing trend with depth (Figure 3),
and most values in the upper part of the section (Upper Domo Shale) are <0.70%Rrandom,
whereas most samples from the lower part of the section (Lower Domo Shale) have vitrinite
reflectances higher than 0.70%Rrandom (Figure 3).
Hydrocarbon potential
The samples analyzed from the Nemo-1X well are characterized by relatively low TOC
levels, with kerogen type III (gas prone) predominant. Despite the fact that the organic
Figure 4. Continued
sample 19, depth 3277 m, Lower Domo Shale Formation, micrograph taken in reflected white light illumination; (c) inertinite fragments associated with mineral matter, sample 31, depth 3615 m, Sena Formation,
micrograph taken in reflected white light illumination; (d) sporinite, sample 20, depth 3295 m, Lower Domo
Shale Formation, micrograph taken under reflected blue light excitation; (e) and (f) solid bitumen (B1—
family 1 and B2—family 2), sample 27, depth 3490 m, Lower Domo Shale Formation, micrograph taken in
reflected white light illumination; (g) bioclast fragments associated with mineral matter, sample 24, depth
3399 m, Lower Domo Shale Formation, micrograph taken in reflected white light illumination; (h) framboidal
syngenetic pyrite associated with mineral matter, sample 17, depth 3197 m, Lower Domo Shale Formation,
micrograph taken in reflected white light illumination.
14
Energy Exploration & Exploitation 0(0)
matter is in the peak maturity stage for liquid hydrocarbon generation, the relatively low
TOC contents and the predominance of kerogen type III are not likely to produce a large
volume of liquid hydrocarbons. There may be, however, a potential for the generation of gas
at higher maturity levels.
Conclusions
The TOC contents of the samples range from poor to good (0.41–1.34 wt%) and show a
tendency to increase with depth; the highest values occurring in the Lower Domo Shale
Formation. These higher levels appear to be associated with solid bitumen that occurs in the
carbonate fractions of these samples.
The analyzed sequence is essentially siliciclastic, although a large part of the Lower
Domo Shale and Sena Formation samples had a carbonate fraction (CaCO3) that reached
40%. The organic matter was preserved in an essentially reducing environment that was
favorable for its preservation, which was also documented by the presence of pyrite in the
entire sequence.
According to the petrographic analyses, the organic matter is dominated by vitrinite and
inertinite macerals, with a minor contribution of liptinite (sporinite), which is typical for a
terrestrial origin kerogen type III. The solid bitumen identified in samples from the Lower
Domo Shale Formation had reflectances ranging from 1.5 to 2.6%Rrandom, which based
on Jacob (1989) were classified as epi-impsonite and meso-impsonite.
The vitrinite random reflectances range from 0.65 to 0.86%Rrandom, suggesting that the
organic matter for the analyzed depth interval (2219–3676 m) is in the peak hydrocarbon
generation stage (catagenesis).
However, hydrocarbon generation potential of the organic matter is limited by the relatively low TOC contents and the predominance of kerogen type III, although there may be
potential for gas generation at higher maturity levels.
Acknowledgments
The first author would like to thank the European Commission for the awarded scholarship (Project
Mundus ACP2), which allowed the opportunity to attend the Master in Geology Program in the
Faculty of Sciences of the University of Porto (FCUP). Empresa Nacional de Hidrocarbonetos
(ENH) provided the well samples and all of the company’s data and documentation and provided
necessary collaboration during the sampling. This work was performed within the cooperation protocol established between the ENH and the FCUP to perform a Master’s Dissertation for
Mozambican students. The authors like to thank Drs. J. Esterle, University of Queensland and N.
Wagner, University of Johannesburg for helpful comments on the manuscript resulting in a significant
improvement.
Declaration of conflicting interests
The author(s) declared no potential conflicts of interest with respect to the research, authorship, and/or
publication of this article.
Funding
The author(s) received no financial support for the research, authorship, and/or publication of this
article.
Mussa et al.
15
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