The Morocco area experienced multiple stages of geological evolution and has undergone sedimentation since the Precambrian. The area hosts multiple sets of marine and continental deposits from the Precambrian, Paleozoic (Cambrian, Ordovician, Silurian, Carboniferous and Permian), Mesozoic (Triassic, Jurassic and Cretaceous) to Cenozoic as well as multiple sets of source, reservoir and cap rocks from the Paleozoic to the Cenozoic, which constitute multiple sets of source-reservoir assemblages. In comparison, the strata developed on the Canadian side include only sandstone, mudstone, carbonate rock and salt rock from the Triassic to the Tertiary, and the plays were mainly deposited during the Jurassic and Cretaceous (Fig. 3). Triassic, Cretaceous, Jurassic and Tertiary plays have been discovered in the onshore Morocco area. Oil and gas discoveries have also been made in the offshore Morocco area. In 1969, the Ras Juby Oilfield in the Upper Jurassic carbonate was discovered offshore in the Tarfaya Basin. In 2009, the Anchois Gas Field in the Eocene-Miocene deep-water turbidite sandstone was discovered in the Rharb Basin. In 2014, the Sidi Moussa 1 Oilfield in the Upper Jurassic shallow-water carbonate was discovered in the Aaiun-Tarfaya Basin (IHS Markit, 2017). The above findings show that the deep-water basins along the passive continental margins offshore Morocco should also have favorable conditions for hydrocarbon accumulation. According to the Canadian Association of Petroleum Producers, the first offshore well in Nova Scotia was drilled in 1967 and the first offshore discovery occurred at Sable Island in 1971. To date, approximately 127 exploration wells have been drilled in offshore Nova Scotia, resulting in 23 significant discoveries. Petroleum exploration has been conducted in the onshore sedimentary basins of Nova Scotia since the 1860s. More than 125 exploration wells have been drilled in various onshore areas, with small amounts of petroleum discovered in approximately one-third of these wells. To date, there has not been any commercial production of oil or natural gas resources in onshore Nova Scotia.
The geochemical parameter total organic carbon (TOC) of the shale/mudstone and marl in the offshore Morocco area and Canada, which are along the eastern and western sides of the Central Atlantic Ocean, respectively, indicates that the Jurassic and Cretaceous mudstones are two major source rocks rich in organic matter (Davison, 2005) (Table 1). Potential source rocks could be found in the unexplored Silurian, Devonian, Carboniferous and Triassic strata. The Jurassic source rock, which mainly formed in a shallow sea to bathyal environment during the passive continental margin stage, has primarily Type II organic matter, TOC contents of 0.4%-4.3% (1.6% on average), and Ro values of 0.8%-1.8%. The Jurassic source rock began to generate oil and was also in the gas generation stage in the Late Cretaceous. The Upper Jurassic Oxfordian shales in the Essaouira Basin are a good source rock with Type II kerogen, TOC up to 4.3%, and thickness of at least a 10 m (Davison, 2005). The Cretaceous source rock, which mainly formed in an open bathyal to deep-sea environment during the passive continental margin stage, largely presents Type II/III organic matter and has TOC contents of 1.6%-2.8% (1.8% on average) and Ro values > 0.5%. The Cretaceous source rock began to generate oil in the Pliocene and has remained in the oil generation stage. Five sets of hydrocarbon source rocks are observed in the Scotian Basin, and they range in age from Aptian, Valanginian, Tithonion-Kimmeridgian, and Callovian to Early Jurassic (Association (OERA), 2016). The hydrocarbon source rocks of the lower cretaceous Aptian and Valanginian deltaic mudstone have Type III kerogen and the average TOC values of 2% and 1.5%, respectively (Association (OERA), 2016). The Upper Jurassic carbonate platform-delta transitional mudstone of the Tithonian Verrill Canyon formation is the main hydrocarbon source rock of this basin, and it presents Type II-III kerogen and an average TOC values of 3% (Association (OERA), 2016). The source rock of Middle Jurassic Miaine stage fluvial mudstone has Type II, III kerogen and a TOC value of 2% (Association (OERA), 2016). The hydrocarbon source rock of Lower Jurassic drift stage marine mudstone has Type II kerogen and a TOC values of 0.5%-2.49%, which is similar to that of Morocco. In general, the main hydrocarbon source rocks on both sides are distributed in Jurassic and Cretaceous mudstone strata. However, due to the differences in sedimentary environments after the rifting of the Atlantic margins, the Mesozoic delta in the Scotian side is more widely developed and the high amount of terrestrial input produced more gas-prone source rocks, whereas the Moroccan side has more oil-prone source rocks.
Region Basin Oil and gas accumulated elements Source rock Reservoir Seal West coast of Central Atlantic Scotian Basin Jurassic-Cretaceous shale, Type II/III kerogen, with an average total organic carbon (TOC) of 3%, up to 10% Upper Jurassic to Lower Cretaceous sandstones, with porosity of 2%-39.1% and permeability of 0.12-2 380 md Jurassic- Cretaceous shale East coast of Central Atlantic Rharb Basin Lower and Middle Jurassic shale and marl, mainly Type II/III, with the TOC values of 1%-7% Paleozoic fractures and decomposed granite, Lower Jurassic sandstone and carbonate rocks, and Miocene sandstone and limestone; up to 8% porosity and 700 md permeability in the fractured granite reservoirs; 20% porosity and 1 000 md permeability in the Lower Jurassic sandstone reservoir Tortonian mudstone of the Miocene Doukkala Basin Silurian black shale, mainly Type II/III kerogen, with a maximum TOC value of 2.4% No proven reservoir, potential Jurassic submarine fan sandstone with average porosity of 15% Paleozoic- Cenozoic multiple mud-rock layer Essaouira Basin Oxfordian Marine shale of Upper Jurassic, Type II kerogen, with the TOC values of 0.49%-4.3% Upper Jurassic Oxfordian sandy dolomite with a porosity of 5%-20%, and a permeability of 2-80 mD, Upper Triassic fluvial sandstone and Lower Jurassic marginal Marine sandstone Triassic-Jurassic evaporite and inner shale Tarfaya Basin The Lower Jurassic-Middle Jurassic mudstone with TOC values of 0.5%-2.49%, Type II/III kerogen, and HI of 500-700 mghc/gTOC; Upper Cretaceous shale with a TOC values of 1.6% to 2.8% and Type II kerogen Upper Jurassic limestone with porosity of 5%-35% and average porosity of 10% Upper Jurassic and Lower Cretaceous shale and Upper Cretaceous and tertiary shale
Table 1. Petroleum system elements for hydrocarbon accumulation factors in conjugate sides of Central Atlantic passive margin basins
In the offshore Morocco area, the proven reservoirs are mainly observed in the Upper Jurassic carbonate rock and Miocene-Pliocene sandstone reservoirs (Table 1), while the potential reservoirs are observed in Triassic sandstone, Lower-Middle Jurassic sandstone and carbonate rock, and Cretaceous sandstone and carbonate rock (Fig. 3). The Upper Jurassic carbonate reservoirs mainly formed in the shallow sea environment of the passive margin (Addi and Chafiki, 2013). The Upper Jurassic carbonate reservoir in the Cap Jub Oilfield of the Tarfaya Basin has a depth of 2 982 m, a porosity range of 5%-35%, and an average porosity of 10% (IHS Markit, 2017). The Early Cretaceous Neocomian submarine delta fan developed in the Tarfaya and Essaouira basins of offshore Morocco, and they could host good sandstone reservoirs (Sibuet et al., 2012). The Miocene-Pliocene turbidite sandstone reservoirs were mainly formed in the deep-sea environment during passive continental margin. The Middle Pleistocene-Pliocene turbidite sandstone reservoirs in the Anchois Gas Field in the Rharb Basin have a depth of 2 359 m and a maximum net thickness of 40 m (IHS Markit, 2017). A fair amount of natural gas reserves have been found in the Triassic sandstone reservoirs in the Tendrara Oil Field of the Atlas Basin, indicating that Triassic sandstone reservoirs may also be deposited in the offshore Morocco area. Reservoirs of the Scotian Basin are from the Upper Jurassic to Lower Cretaceous deltaic sandstones sediments of the Missisauga and Logan Canyon formations, which have a thickness of several kilometers, porosity of 2%-39.1%, and permeability of 0.12-2 380 md (Zhang et al., 2015). In addition to the mudstone caprocks in the Middle Jurassic-Pliocene strata, Triassic evaporite (salt) rocks are distributed across the whole basin in offshore Morocco in the form of salt walls, salt domes and salt stock canopies, which pierce into the Tertiary strata (Fig. 3) and provide favorable structures for oil and gas accumulation (such as presalt anticlines and post-salt anticlines and monoclines) and capping conditions.
3.1. Comparison of Source Rocks between Offshore Morocco and Nova Scotia
3.2. Comparison of Reservoirs and Caprocks between Offshore Morocco and Nova Scotia
The deep-water basins along the passive margins in Morocco and Canada have undergone multiple stages of basin evolution but with some differences. The Moroccan deep-sea basins have undergone multiple stages of evolution from the Paleozoic to the present, while the Canadian deep-water Scotian Basin began to settle and has gradually formed since the Triassic. During the Cenozoic, the deep-water basins in Morocco were squeezed and uplifted due to the influence of the Atlas orogeny, while the deep-water Scotian Basin continued a passive margin evolution in an extensional environment (Fig. 4) (Kidston et al., 2002). In addition, due to the differences in tectonic evolution, the continental shelf of the deep-water Scotian Basin is wide and provides more lateral depositional space, whereas the continental shelf of the Moroccan deep-water basins is narrow and the steep continental shelf and continental slope allow for rapid settlement and provide ample space for vertical sediment accumulation (Tari et al., 2012).
Figure 4. Tectono-stratigraphic evolution of the Moroccan margin and its conjugate Nova Scotian margin (compiled after Tari et al., 2012), (a) tectonic and basin evolution in the conjugate margins from 180 to 110 Ma; (b) stratigraphic correlation of the conjugate margins.
The reservoirs in the terrestrial and offshore basins of Morocco are distributed in the Paleozoic, Triassic, Jurassic, Cretaceous and Neogene stratas (Table 2). Among these reservoirs, the Triassic sandstone reservoirs contribute the largest reserve of 78 mmboe (43% of total reserves). The Neogene and Jurassic sandstone and carbonate reservoirs are dominated by continental and neritic facies. The reserve of Neogene marine sandstone reservoirs is 48 mmboe (contributing 27% of the reserves), and the reserve of Jurassic neritic carbonate reservoirs is 38 mmboe (contributing 21% of the reserves). The Cretaceous sandstone reservoirs are dominated by deep-water facies. The reserve of Cretaceous sandstone reservoirs is 9 mmboe (5% of total reserves). In addition, continental Paleozoic granite and slate reservoirs have also been found in Morocco, and their reserves are 5 mmboe (2% of the total reserves). The reservoirs in the deep-water Scotian Basin are mainly distributed in the Jurassic and Cretaceous neritic facies of sandstone and carbonate rock strata. The reserve of shallow-water Jurassic sandstone reservoirs is 187 mmboe (13% of the total reserves), and the reserve of shallow-water Jurassic carbonate reservoirs is approximately 150 mmboe (11% of the total reserves). The reserve of the Cretaceous neritic sandstone reservoir is 287 mmboe (20% of the total reserves), and the reserve of Cretaceous deep-water turbidite sandstone reservoirs is 172 mmboe (12% of the total reserves). Most of the discovered reservoirs in the Moroccan deep-water basins are Triassic and Neogene deep-sea turbidite sand bodies, while most of the discovered reservoirs in the deep-water Scotian Basin are Jurassic and Cretaceous shallow marine delta sand bodies (Fig. 5).
Region Geological time of reservoir 2P reserves of different reservoirs (mmboe) Carbonate Sandstone Granite Total Morocco Cretaceous 0 9 0 9 Jurassic 35 3 0 38 Neogene 5 43 0 48 Paleozoic 0 0 5 5 Triassic 0 78 0 78 Nova Scotia Cretaceous 23 499 0 521 Cretaceous/ Jurassic 0 633 0 633 Jurassic 153 92 0 245
Table 2. Reserves distribution in various types of reservoirs in Moroccan and Scotian basins
Figure 5. Comparative analysis of the reservoirs and reserve distribution features in the deep-water basins of Morocco and Nova Scotia. (a) Reserves from different types of reservoirs of different geologic periods in the basins in onshore and offshore Morocco areas; (b) reserve proportions among different depositional facies in the basins in onshore and offshore Morocco areas; (c) reserves from different types of reservoirs of different geologic periods in the Scotian Basin at different times; (d) reserve proportions among different depositional facies in the Scotian Basin.
The main reason for this difference in reservoir age and facies may be that in the Cenozoic, Morocco experienced uplifting and denudation due to the Atlas orogeny and a large amount of transportable materials formed at the source of rivers, which provided favorable conditions for the supply of clastic rocks into the deep-sea basins. However, the difference in the ancient river distribution among the geological periods between these two regions may be the main factor. According to Gabor Tari's study, the multistage Cretaceous delta deposits were formed in the Scotian Basin in the west side of the Central Atlantic, while the latest drilling in the offshore Moroccan area on the east side of the Central Atlantic indicates that only Tan-tan deep-water fan depositions were developed in the Early Cretaceous; therefore, oil and gas accumulation in Morocco depends on the presence of reservoirs (Tari et al., 2012). Additionally, there may be too few deep-water drilling wells in the offshore Morocco area to reveal the deep Jurassic and Cretaceous reservoirs.