Petroleum source rock characteristics of the Mesozoic units, Mekelle Basin, northern Ethiopia
Article Category: Original Scientific Article
Online veröffentlicht: 04. Sept. 2023
Seitenbereich: 1 - 13
Eingereicht: 11. März 2022
Akzeptiert: 28. März 2022
DOI: https://doi.org/10.2478/rmzmag-2021-0019
Schlüsselwörter
© 2022 Damenu Adefris et al., published by Sciendo
This work is licensed under the Creative Commons Attribution-NonCommercial-NoDerivatives 3.0 License.
Petroleum is considered as one of the geologic resources of Ethiopia and potential oil and gas occurrences are expected from the Ogaden, Blue Nile, Mekelle, Gambela and Southern Rift Basins [1]. Paleozoic shale units served as sources of hydrocarbon that fed sandstone and carbonate reservoirs and led to the formation of a significant amount of the world’s oil and gas resource [2] [3]. Large reserves of oil and gas were discovered within the Permian sandstone and carbonate reservoirs sourced mainly by Silurian shales throughout the Middle East (e.g., Iran, Iraq and Arabia) [4]. The Permian Calub Sandstone and Bokh Shale are also good reservoirs and source rocks respectively in the Ogaden Basin, Ethiopia [5, 6]. The middle to upper Jurassic formations which comprised limestone, dolostone, marl, shale and sandstone are also known to have the potential for petroleum occurrences [5–12]. The Ogaden Basin was intensively investigated and has become the focus of oil companies to look for petroleum due to potential discoveries of gas fields at Shilabo, Calub and Hilala [5]. And, the Blue Nile Basin was the second target and studied in terms of petroleum system [9, 13], whereas the petroleum potential of Mekelle Basin has not been studied except the discovery of oil shale deposits within the Paleozoic glacial sediments [14]. However, the presence of possible potential source rocks within the Mesozoic units was reported by different workers even if detailed evaluation of quality, quantity and maturity of the organic matters have not been carried out. These units include the Agula Shale and Antalo Limestone with brown to black micritic limestone, beds of mudstone, brown shale and greenish-black limestone interbeds [15–16]. The Mekelle Basin requires a detailed evaluation of hydrocarbon prospectivity [1]. Therefore, this study is aimed at evaluating the petroleum source rock potential of these limestone and shale units including the Adigrat Sandstone.
The evolution of the Mekelle Basin is thought to have a close relationship with the East Africa Mesozoic rift basins, developed following the breakup of Gondwana [17]. Subduction along the Tethyan margin was considered to be the cause for the development of tensional stress in the Gondwana plate and its eventual breakup (Figure 1a) [18]. The breakup process was also triggered by the Permo – Triassic mantle plume, situated beneath the Karoo province, South Africa, that thermally weakened the lithosphere and contributed to the intracontinental rifting, widespread crustal extension and subsidence [18, 19]. These processes led to the development of the Permo – Triassic rift systems in the eastern part of Africa and created northwest-southeast trending aulacogen-like basins, reaching up to western and central Ethiopia [17, 20–22] (Figure 1b).
Figure 1:
(a) Map showing Gondwana breakup (after [18]); (b) Mesozoic rift basins of the Horn of Africa including Ethiopia (after [21]).
The sedimentation began in the late Paleozoic within these fault-controlled depositional environments [17, 19, 20, 23–28]. These rift-controlled sedimentary basins, in Ethiopia, include the Ogaden, Blue Nile and Mekelle Basins. The Mekelle Basin has also been considered as an intracontinental sag basin, formed due to cooling and thickening of a juvenile sub-continental lithospheric mantle and subsequent subsidence [29].
Some previous studies documented the petroleum potential of the Ogaden Basin [5, 6, 30–33]. [9, 13] investigated the hydrocarbon potential in the Blue Nile Basin. The Mekelle and Omo basins were investigated by [14, 34] respectively. The Mekelle Basin covers 8000 km2 and comprises over 2000 meters thick Paleozoic to Mesozoic sedimentary successions [35] (Figure 2) which are considered to have geologically good properties to look for hydrocarbon [16].
Figure 2:
Geological map of the Mekelle Basin with sampling locations (after [42]). The inset map is a simplified geological map of Ethiopia (after [43]).
The Paleozoic units comprise about 300 meters thick of glacial origin clastic rocks [36] which were, first, described and subdivided into glacial sandstone (Enticho Sandstone) and tillite facies (Edaga Arbi Tillite) [37]. The Edaga Arbi Tillite was later named Edaga Arbi Glacial which comprises tillite, siltstone and shale facies [35]. Enticho Sandstone was also subdivided into two members; Lower Enticho Sandstone and Upper Enticho Sandstone [38]. Detailed facies analysis revealed that the late Paleozoic sediments (Upper Enticho Sandstone and Edaga Arbi Glacial) were formed due to a wide range of glaciogenic processes and depositional environments including sub- aquatic environments with two major glacier advance-retreat cycles [39]. Oil shale deposit was discovered, sandwiched between the Enticho Sandstone and Edaga Arbi glacials and, in some places, underlying the Adigrat Sandstone which has an average mineable bed-thickness of 55 meters, covering an area of 30 km2 with an estimated reserve of 4 billion tonnes [14]. The Triassic to middle Jurassic unit (Adigrat Sandstone) is about 300–650 meters thick and is considered to have a very good reservoir potential for petroleum [15, 16, 35]. The unit comprises fine-grained to coarsegrained sandstones and interbeds of siltstone and clay which were deposited in continental and shallow marine environments during the Triassic-middle Jurassic [35, 36].
The middle to upper Jurassic unit is carbonate (Antalo Limestone) with about 740 meters thick dominated mainly by yellow, white to black limestone with significant interbeds of marl, lenses of chert and cross-bedded sandstone [15–17, 35]. The brown shale and black limestone interbeds of the Antalo Limestone could serve as very good potential source rocks [16]. The unit has some reservoir potential [40]. The unit is also considered as a marine shelf carbonate facies, equivalent to the Mesozoic carbonate units of the Middle East Arabian Basins having potential for oil and gas occurrences [41]. In the Ogaden Basin, the marl and shale layers of Uarandab Formation are potential source rocks, with Type II kerogen, having petroleum potential that ranges from 2 kg/ton to 20 kg HC/ton of rock [5]. The black shales and mudstones of the Upper Hamanlei of the Blue Nile Basin, are also matured source rocks for oil generation, with TOC up to 7 wt.% and hydrogen index (HI) between 465 mgHC/g and 660 mgHC/g [9]. The Agula Shale is characterized by gray to black shale, marl and clay subunits with inter-laminae of black limestone, gypsum and dolomite, and has 60 to 250 meters thickness that was deposited in lagoons under semiarid conditions [15] [35]. The Amba Aradam Sandstone is upper Jurassic-lower Cretaceous in age [15, 17] which conformably overlies the Agula Shale. It is 60–200 meters thick and comprises medium to coarse-grained white to pink color sandstone facies (at the northern part of the basin) and white sandstone and conglomerate facies with some clayey beds (at the southern part of the basin) [35]. It has been confirmed, from the present study, that a highly conglomeratic sandstone composed of very coarse pebble size and well rounded quartz grains is exposed in the southern part of the basin whereas in the northwestern part of the basin, it is very fine-grained with yellow, pink to reddish colors. This unit was deposited in fluvial-lacustrine depositional environments and is assumed to be a very good reservoir rock in the basin [16, 35].
A total of fifteen samples made up of five black limestones and ten shales were collected from four outcrop locations for organic geochemical analyses. The samples were collected from the Adigrat Sandstone (one sample), Antalo Limestone (twelve samples) and Agula Shale (two samples). The petroleum potential of the samples was assessed from the Total Organic Carbon (TOC) and Rock-Eval pyrolysis. All laboratory procedures were carried out following the Norwegian Industry Guide to Organic Geochemical Analyses, fouth edition [44], at the Applied Petroleum Technology Ltd, (ALS Oil & Gas), UK. About 100 mg of sample was pulverized and diluted hydrochloric acid (HCl) was added to the pulverized rock samples to remove carbonate. The samples were then introduced into the
The investigated outcrop locations are Giba River, Mesobo, Enadayesus and Chelekot sections (Figure 3) where the studied layers from the Adigrat Sandstone, Antalo Limestone and Agula Shale represent black limestone and shale (Table 1). About 70 meters thick black limestone with the associated shale layer was logged from the Mesobo section which is found approximately 5 km north of the Mekelle town (Figure 4a). The shale layers are gray to black, with variable thicknesses ranging from 10 cm to 3 m (Figure 4b). At the vicinity of Mekelle town, thickly bedded black fine-grained limestone (30 cm to 1.3 m in thickness) associated with cyclic layers of black to gray shale, was identified along a stream-cut which represents about 16 meters thick part of the Antalo Limestone (Figure 4c). The shale beds are relatively consolidated, slightly greenish to gray, with well-developed, very thin laminations. Fissility is observed within the loose to semiconsolidated layers, whereas the consolidated layers are characterized by conchoidal fractures. At the bottom of this outcrop, there is a very thick loose to highly consolidated black shale, with thickness ranging from 40 cm to 4 m (Figure 4d). Around Giba River which is located about 25 km northwest of Mekelle town, gray-black shale layers with thickness ranging from 5 cm to 10 cm were also identified from the upper part of Adigrat Sandstone (Figures 5a, b). Gray-black shale layers also represent a significant part of the Agula Shale (Figure 5c).
Figure 3:
Lithologic logs showing the locations of samples collected for source rock characterization.
Figure 4:
Outcrop photographs showing black shale layers and limestone beds within the Antalo Limestone at the central part of the Mekelle Basin. (a) thickly bedded black fine-grained limestone (Mesobo section, sample MS-1); (b) black shale within black micritic limestone beds (sample MS-7); (c) 16 m thick stream-side cliff exposure comprising limestone and shale beds (samples EY-2 to EY-5) around Mekelle town (Endayesus section); (d) Black shale along stream at the bottom of Endayesus section (sample EY-1).
Figure 5:
Outcrop photographs showing black shale layers within the Adigrat Sandstone and Agula Shale, at the central part of the Mekelle Basin. (a) lower part of Antalo Limestone conformably overlies the upper part of Adigrat Sandstone at Giba River section; (b) about 5–10 cm thick oil shale beds (sample GV-1) from the upper part of Adigrat Sandstone; (c) Some part of the Agula Shale at Chelekot section (samples; CH-1, CH-2).
Outcrop samples collected for organic geochemical analyses.
| Sample no. | Sampling location | Sample type | Formation |
|---|---|---|---|
| CH-1 | 13°25’36’’, 39°23’39’’, 1912 m asl. | limestone | Agula Shale |
| CH-2 | shale | Antalo Limestone | |
| EY-1 | 13°29’26’’, 39°29’07’’, 2113 m asl. | shale | |
| EY-2 | shale | ||
| EY-3 | shale | ||
| EY-4 | limestone | ||
| EY-5 | shale | ||
| MS-1 | 13°33’23’’, 39°30’36’’, 2094 m asl. | limestone | |
| MS-2 | shale | ||
| MS-3 | shale | ||
| MS-4 | limestone | ||
| MS-5 | limestone | ||
| MS-6 | shale | ||
| MS-7 | shale | ||
| GV-1 | 13°37’55’’, 39°24’51’’, 1818 m asl. | shale | Adigrat Sandstone |
The results of measured and calculated source rock parameters for fifteen (15) limestone and shale samples are shown in Table 2. Two shale samples of the Mesobo section (MS-2 and MS-7), have 0.50 wt.% and 0.92 wt.% TOC values respectively, whereas the remaining five samples (MS-1, MS-3, MS-4, MS-5, MS-6), have TOC between 0.10–0.41 wt.%. From the Endayesus section, only one shale sample (EY-2), has 0.77 wt.% TOC while the remaining four samples have TOC values ranging from 0.2 to 0.25 wt.%. A shale sample from the underlying Adigrat Sandstone, in the Giba River section, recorded 0.42 wt.% TOC. In the Chelekot section, two samples from the overlying Agula Shale have 0.18 wt. % and 0.40 wt. % of TOC respectively. Only three samples (EY-2, MS-2 and MS-7) have TOC values above the 0.5% threshold [45]. The S3 values which represent CO2 content within the kerogen are relatively high compared to the S1 and S2 values (Table 2).
Rock-Eval pyrolysis data of the analyzed samples.
| Sample no. | Sample type | TOC (wt.%) | S1 | S2 | S3 | Tmax | HI | OI | PI | PP |
|---|---|---|---|---|---|---|---|---|---|---|
| CH-1 | limestone | 0.18 | 0.00 | 0.00 | 0.17 | 327 | 0 | 94 | -- | 0.00 |
| CH-2 | shale | 0.40 | 0.01 | 0.00 | 0.25 | 524 | 0 | 62 | 1.00 | 0.01 |
| EY-1 | shale | 0.25 | 0.00 | 0.00 | 0.26 | 498 | 0 | 106 | -- | 0.00 |
| EY-2 | shale | 0.77 | 0.01 | 0.01 | 0.20 | 485 | 1.3 | 26 | 0.50 | 0.02 |
| EY-3 | shale | 0.20 | 0.00 | 0.01 | 0.98 | 495 | 5 | 488 | 0.00 | 0.01 |
| EY-4 | limestone | 0.21 | 0.02 | 0.07 | 0.64 | 475 | 34 | 309 | 0.22 | 0.09 |
| EY-5 | shale | 0.23 | 0.00 | 0.00 | 0.26 | 496 | 0 | 111 | -- | 0.00 |
| MS-1 | limestone | 0.11 | 0.00 | 0.00 | 0.30 | -- | 0 | 275 | -- | 0.00 |
| MS-2 | shale | 0.50 | 0.00 | 0.02 | 0.39 | 493 | 4 | 78 | 0.00 | 0.02 |
| MS-3 | shale | 0.41 | 0.00 | 0.01 | 0.51 | 505 | 2.44 | 125 | 0.00 | 0.01 |
| MS-4 | limestone | 0.10 | 0.00 | 0.00 | 0.28 | 484 | 0 | 294 | -- | 0.00 |
| MS-5 | limestone | 0.22 | 0.00 | 0.00 | 0.26 | 484 | 0 | 119 | -- | 0.00 |
| MS-6 | shale | 0.20 | 0.00 | 0.00 | 0.39 | 491 | 0 | 194 | -- | 0.00 |
| MS-7 | shale | 0.92 | 0.02 | 0.02 | 1.10 | 519 | 2 | 119 | 0.50 | 0.04 |
| GV-1 | shale | 0.42 | 0.00 | 0.00 | 0.35 | 527 | 0 | 83 | -- | 0.00 |
The most critical parameters such as; TOC and Rock-Eval S1 and S2 values for most of the studied samples are below the standard for any form of hydrocarbon generation, which are unlikely to be considered as petroleum source rocks. The total organic content (TOC) below 0.5 wt. % and S2 values below 2.5 mg HC/g are generally considered as poor source rocks [46–49]. Twelve of the studied samples have TOC between 0.11–0.42 wt.% which is in the range of poor quality whereas three of the shale samples with 0.5–0.92 wt.% indicate fair organic matter richness. However, S2 values are too low with very high pyrolysis Tmax. The type of kerogen and its source organic matter has been determined from a cross plot of hydrogen index (HI) and oxygen index (OI) (Figure 6a) by which Type IV kerogen with a high amount of organic carbon dioxide was identified for all of the analyzed limestone and shale samples. Type IV kerogen is derived from highly oxidized or reworked material of any origin [48, 50, 51]. The TOC and pyrolysis yield (S2) cross-plot also show very poor quality organic matter [47, 50] (Figure 6b).
Figure 6:
(a) Oxygen index (OI) and hydrogen index (HI) cross plot for the recognition of kerogen types (after [57]); (b) Kerogen type based on TOC versus pyrolysis yield (S2) cross-plot, showing very poor quality organic matter for hydrocarbon generation (after [47]).
The thermal maturity of the analyzed shale and limestone samples was determined from the Rock-Eval Tmax which is the temperature at which the S2 peak occurs during pyrolysis and can be correlated with the type of organic matter (kerogen) [46, 52–55]. The different levels of thermal maturity of the organic matters which are determined from Tmax could qualitatively and quantitatively be expressed as immature (<435 0C), early mature (435–445 0C), peak mature (445– 450 0C), late mature (450–470 0C) and postmature (>470 0C) [48]. Therefore, thermal maturity together with the other source rock parameters such as the total organic carbon (TOC) is significant to determine the quality of a given source rock [56]. The measured Tmax value for one sample is 327 0C which max shows an immature stage and nine samples have Tmax that ranges 475–498 0C and four samples are in between 505–527 0C indicating post mature stage. The level of thermal maturity could also graphically be determined from T and hydrogen index cross max plot (Figure 7a). Hence, the maturity level of the organic matter in all of the analyzed samples indicates a post-mature stage.
Figure 7:
(a) Rock-Eval Tmax versus hydrogen index (HI) plot showing the thermal maturity level of the organic matter (after [57]); (b) TOC versus (S1+ S2) cross-plot, indicating poor hydrocarbon generating potential (after [47]).
The hydrocarbon generating potential of source rocks is indicated with the sum of Rock-eval S1 and S2 values, which could be expressed qualitatively and quantitatively as; poor (0–3 mgHC/g), fair (3–6 mgHC/g), good (6–12 mgHC/g), very good (12–24 mgHC/g) and excellent (>24 mgHC/g) [46–48]. The S1 values for most of the samples are 0.00 mgHC/g, with some samples having 0.01–0.02 mgHC/g values. S2 values for nine (9) of the studied samples are 0.00 mgHC/g, whereas the remaining six (6) samples range from 0.01 to 0.07 mgHC/g. Therefore, both the S1 and S2 values indicate that the studied samples have a very low potential for any form of hydrocarbon generation. Cross plot of S1 + S2 vs TOC shows that the samples have poor oil generating potential (Figure 7b).
Field evidence showed that the studied units comprised black shale and black limestone beds which seem having adequate organic matter. However, the organic geochemical analyses revealed low organic content of the analyzed samples, indicating that the black color of the samples is not a diagnostic feature of organic richness which could most probably be due to iron oxide impurities. The TOC values of a few samples indicate fair organic matter richness whereas about 80% of the samples have poor organic matter quality. The cross-plots of oxygen and hydrogen indices as well as S2 versus TOC indicate Type IV and dray gas-prone kerogen. The Tmax versus hydrogen index crossplot shows that the organic matter is in a late catagenesis stage and thermally over-mature. Therefore, the source rock parameters indicate poor petroleum generating potential. However, since some outcrop samples of the Antalo Limestone have shown fair organic richness, further study is required, especially from core samples, to assure the source rock potential of this unit.