## 4 Discussion
### Source-Rock Hydrocarbon Potential and Deposition Environment  
Geochemical and petrographic data from the NGJ, KWB, and TRC wells provide insights into the depositional environments and source-rock potential of the shales of the Albert Rift during the Miocene and Pliocene epochs. In the NGJ well, TOC values range  
Figure 18: PetroMod-generated petroleum system events chart for the pseudo-well X.  
from 0.11% to 0.48%, indicating poor source-rock quality. HI values are in the range of 9-123 mgHC/g TOC, reflecting varying organic matter input, but exclusively gas-prone. The KWB well shows relatively higher organic richness, with TOC contents between 0.17% and 0.68% and HI values of 28-259 mgHC/g TOC, suggesting more oil-prone material compared to Well NGJ. In contrast, the TRC well exhibits significantly higher TOC values (0.56% to 7.99%, averaging 3.5%) and HI values of 89-502 mgHC/g TOC, with an average of 367 mgHC/g TOC, indicating good-to-excellent source-rock potential. The Kasande-Kakara-Oluka-Nyaburogo shale intervals in Well TRC, spanning the Mid-Moocene to Early Pliocene, are classified as good-to-very good source-rock facies. The lower section (Mid-Moocene) is predominantly oil-prone, while the upper section (Upper Miocene to Early Pliocene) is gas-prone. Organic microscopy of the samples as presented in the TRC well reports and other data show dominance of vitrinite and inertinite in the upper section e.g., [46], with the lower section containing strongly fluorescent algal kerogen, which explains the higher HI values. The petrographic kerogen data (e.g., liptinite, amorphous organic matter, and vitrinite), total organic carbon (TOC), and hydrogen index (HI) trends observed in the TRC well suggest a strong environmental control over the organic matter type and hydrocarbon-generation potential. Petrographic data from the TRC well indicate a predominance of Type I kerogens over Type III, with this dominance gradually decreasing from the lower to the upper sections of the succession. Kerogen type is a critical factor in determining the hydrocarbon potential of a source rock, as it dictates both the quantity and type of the hydrocarbons generated during thermal maturation. Kerogen is normally classified into four types: Type I (oil-prone), Type II (mixed oil and gas), Type III (gas-prone), and Type IV (inert). Type I kerogen, rich in hydrogen, is predominantly derived from lacustrine environments and generates mainly oil, especially at lower thermal maturities, while Type II, typically marine in origin, produces both oil and gas, with oil generation decreasing as thermal maturity increases, eventually shifting to gas at higher maturities. Type III kerogen, which is derived from terrestrial plant material, is gas-prone and predominantly produces natural gas, with gas generation intensifying as maturity exceeds the oil window. Type IV kerogen is largely inert and contributes little to hydrocarbon generation. The predominance of Type I kerogens suggests that the Albert Rift primarily represents an oil-prone system with limited gas generation. This interpretation is supported by the HI values presented in this paper. Based on the high HI values and the predominance of oil-prone kerogen in the lower section of the well, it was hypothesized that these intervals were deposited in a nutrient-rich, eutrophic zone of an open lake, with minimal fluvial input, and that they have the potential for higher oil-to-gas generation ratios, compared to the upper sections with lower HI values. Such depositional settings, characterized by low terrigenous plant material influx, are often associated with high algal productivity, as seen in global analogs like the Green River Formation in the U.S. and the Eocene Mahakam Delta in Indonesia, where lacustrine to marginal lacustrine conditions are conducive to the deposition of high-quality, oil-prone source rocks [4; 47].