Browsing by Author "Sabuni, Rachel"

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    Geologic review of hydrocarbons potential of the Rufiji Basin, Tanzania
    (Springer, 2022-04-15) Sabuni, Rachel; Mtelela, Cassy; Kagya, Meshack
    The Rufiji Basin is one of the underexplored and least studied basins in the coastal Tanzania, despite the occurrences of oil and gas seeps that indicate the presence of a working petroleum system(s). Consequently, geology and distribution of key petroleum elements and hydrocarbon potentiality of the basin remains poorly understood. This study presents a geological review of the hydrocarbon potential of the Rufiji Basin based on a synthesis of published and unpublished reports of multifaceted studies in the basin, coupled with very limited additional data collected in the course of this study. This review identifies three petroleum plays (play I, play II, and play III) along with associated components, and includes: hydrocarbons play I, which constitutes a Permian–Triassic source rocks that are characterized by kerogen type III with TOC of ~ 6.1 wt% and Tmax values of 465 °C, along with Permian–Triassic fluvial–deltaic sandstone reservoir units, with porosity varying from 7 to 18%; and a Bajocian (restricted marine shales) as a seal. Play II has Bajocian restricted marine shale source rocks that are correlated to kerogen type II/III and III Makarawe shales, which have an average TOC of 1.7 w% and Tmax of 450 ℃, and is marked by Middle Jurassic carbonate reservoirs with an average porosity of 15%, capped with mid-Late Jurassic marine shales. Play III is characterized by Campanian shales as source rocks, Early Cretaceous fluvial–deltaic sandstone reservoir with a porosity of 15–20%, and is capped by Late Cretaceous transgressive marine shales. The analyses indicate that plays I and II are particularly more prospective, as manifested by the gas reserves discovered in offshore Songo Songo Island, making a Rufiji Basin a viable potential basin for hydrocarbon generation and accumulation. The findings of this review study support follow up exploration activities and researches, which can ultimately lead to a commercial discovery oil reserves in the basin.
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    Geologic review of hydrocarbons potential of the Rufiji Basin, Tanzania
    (Springer, 2022-05-06) Sabuni, Rachel; Mtelela, Cassy; Kagya, Meshacky
    The Rufiji Basin is one of the underexplored and least studied basins in the coastal Tanzania, despite the occurrences of oil and gas seeps that indicate the presence of a working petroleum system(s). Consequently, geology and distribution of key petroleum elements and hydrocarbon potentiality of the basin remains poorly understood. This study presents a geological review of the hydrocarbon potential of the Rufiji Basin based on a synthesis of published and unpublished reports of multifaceted studies in the basin, coupled with very limited additional data collected in the course of this study. This review identifies three petroleum plays (play I, play II, and play III) along with associated components, and includes: hydrocarbons play I, which constitutes a Permian–Triassic source rocks that are characterized by kerogen type III with TOC of ~ 6.1 wt% and Tmax values of 465 °C, along with Permian–Triassic fluvial–deltaic sandstone reservoir units, with porosity varying from 7 to 18%; and a Bajocian (restricted marine shales) as a seal. Play II has Bajocian restricted marine shale source rocks that are correlated to kerogen type II/III and III Makarawe shales, which have an average TOC of 1.7 w% and Tmax of 450 ℃, and is marked by Middle Jurassic carbonate reservoirs with an average porosity of 15%, capped with mid-Late Jurassic marine shales. Play III is characterized by Campanian shales as source rocks, Early Cretaceous fluvial–deltaic sandstone reservoir with a porosity of 15–20%, and is capped by Late Cretaceous transgressive marine shales. The analyses indicate that plays I and II are particularly more prospective, as manifested by the gas reserves discovered in offshore Songo Songo Island, making a Rufiji Basin a viable potential basin for hydrocarbon generation and accumulation. The findings of this review study support follow up exploration activities and researches, which can ultimately lead to a commercial discovery oil reserves in the basin.
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    Intergrated Seismic Stratigraphic and Structural Analysis of the Songo Songo Gas-Field, Shallow Offshore Tanzania, Using Seismic and Well Data
    (Journal of Geology & Geophysics, 2019-03-16) Sabuni, Rachel
    Seismic stratigraphy and structural analysis of seismic data, when combined with wireline data, provides vital information for hydrocarbon exploration in a prospective basin. These techniques were employed in the Songo Songo shallow coastal basin, southern Tanzania to determine stratigraphic setting, trapping mechanism, reservoirs zones. Suites of well logs from two wells (AA-1 and BB-5) and 2-D seismic data was obtained from TPDC in the study area. Lithologic interpretation and well correlation were carried out using the well log suites. Stratigraphic analysis was carried out with the well logs and 2D seismic data by using principles of sequence stratigraphy while structural interpretation was done with aid of the seismic data to produce polar plots for the different structural trends. The lithology was dominated by sand, shale, and limestone. Five sequence boundaries (SB); SB1 (Albian), SB2 (base of Coniacian-Early Campanian), SB3, (Middle Eocene), SB4 (Late Miocene) and SB5 (Quaternary)) and three maximum flooding surfaces (MFS); MFS1-(Early Cretaceous), MFS2, (Late Cretaceous), MFS3-(Early Eocene) were identified. Three main normal faulting systems (Jurassic faults, active during the Jurassic rifting phase of Madagascar, Neogene faults that occurred during Neogene east African rifting and reactivated faults which mostly were Jurassic fault reactivated by east African rifting) of NNW-SSE were recognized in the study area. The structural interpretation reveal that the gas field is dominated by normal faults that occur in the upper and lower part of Songo Songo suggesting two phases of deformation prior to development of the field. The main reservoir is developed in the Neocomian and Albian sandstones, and capped by Jurassic faults and Wami (Formation) overlying rocks. The gas is sourced from Jurassic shale known as Mtumbei Formation and stored at the main reservoir developed in the Lower Cretaceous aged Neocomian sandstone known as Kipatimu Formation, sealed by high pressured shale of upper Cretaceous known as Wami Formation. This study shows that deposition of sediment occurs in the NW – SE direction, with the thinning of sediments thickness towards well BB-5 while the stratigraphic sections show that the horizons are laterally continuous and are being strongly affected by tectonic events.
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    Petroleum systems and hydrocarbon potential of the Ruvuma Basin, Tanzania
    (ELSEVIER, 2023-02-18) Sabuni, Rachel
    Ruvuma Basin is widely recognized across the world for large gas field discoveries, which indicate the presenceof gas-prone sources. However, little is known about the basin’s source rock’s hydrocarbon generation potential, including the distribution of significant petroleum systems. Inferences are often drawn from Permo-Triassic and Jurassic source rocks in Mandawa Basin, Tanzania and Morondava Basin, Madagascar. As a result, knowledge ofthe basin’s potential source rocks is not known. To constrain possible source beds including petroleum systems, this study thoroughly reviewed previous literature coupled with rock eval pyrolysis and vitrinite reflectance analysis on rock cuttings (n = 19) from the Ruvuma Basin’s Permo-Triassic, Jurassic, and Cretaceous shales of Lukuledi-1 well. The findings indicate variable petroleum systems with different generation potentialities in the Permo-Triassic, Jurassic, Cretaceous, and Cenozoic intervals. The Permo-Triassic plays sourced hydrocarbons from the matured Permo-Triassic shales of kerogen type II and I, with Total Organic Carbon (TOC) average of 40 %wt, Hydrogen index (HI) average of 286.5 mg HC/g TOC, vitrinite reflectance (Ro%) average of 0.81 with Tmax average of 436 ◦C capable of oil generation. The Jurassic play systems are charged from matured Jurassic kerogen type III and mixed type II/III shales with TOC~ 4 %wt, HI~54.25 mg HC/g TOC, Ro% ~0.6 and Tmax ~444 ◦C capable of gas generation. Cretaceous and the Cenozoic play systems, sourced hydrocarbon from deeper sources because their source rocks are thermally immature with kerogen type III, having TOC ~0.6 %wt, HI ~53.6 mg HC/g TOC, Ro% ~0.3 and Tmax <420 ◦C capable of gas generation. These results indicate that the Cenozoic play system incorporates hydrocarbons from diverse sources/reservoirs, making it a potential exploration target for future discoveries. These findings necessitate more research to determine migratory patterns, which will result in new ground-breaking discoveries in the basin.