This current study utilized quantitative data, mainly of geochemical data analyzed using High Performance Liquid Chromatography (HPLC) and Gas Chromatography-Flame Ionization Detector (GC-FID) and Gas Chromatography-Mass Spectrometry (GC-MS) of oil seeps and oils recovered from some of the wells in the Albertine Graben drilled by Tullow in 2007. The data from the wells, namely Waraga-1, Nzizi-2 Murram Pit, Nzizi2, MPuta-1, Mputa-3, Mputa-4, Runga, Sonso and Kibiro seep obtained from the Directorate of Petroleum (DOP), Entebbe, Uganda. The relevant data was subsequently selected and presented in the workflow ( Figure 2 ) to illustrate systematic flow of the methodology and analysis.

Data and interpretive ratios obtained from quantitative data-set were tabulated and various interpretive ratios/values and figures derived. The identification and selection of data was based on the importance of each parameter in relevant to specific objective. Where necessary, as in the case of HPLC data, data was normalised before plotting to appropriate interpretive diagram.

The extent of biodegradation among oil and oil seep samples were assessed from HPLC and GC-FID data. From the HPLC data, it can be seen that Mputa-1, Mputa3, Mputa-4, Waraga-1, Nzizi2 oil samples have saturates/aromatics ratios greater than 1 indicating non-degraded oils while Kibiro, Nzizi-2 Murram Pit, Runga and Sonso oil seep samples have sats/aros ratios less than 1 indicating biodegraded oil seeps. This is actually expected given that they have been exposed to oxidation during seepage.

The GC-FID traces for all oil seeps are indicated in Figure 3(a) . It noted that Kibiro, Nzizi-2 Murram Pit, Runga and Sonso have no traces of n-alkanes (n-C₁₇, n-C₁₈, Pr and Ph) and their baseline humps have been elevated to greater extent, implying heavy biodegradation concurring with observations and interpretation of sats/aros from HPLC data above.

The 5 traces of GC-FID for oils ( Figure 3(b) ), show intact n-alkanes (n-C₁₇, n-C₁₈, Pr and Ph) and a relatively straight baseline humps. These samples represent oils recovered from Mputa-1, Mputa-3, Waraga-1, Mputa-4 and Nzizi-2. This clearly suggests that these oils are non-degraded.

A plot of saturates, aromatics and NSO + Asph on Ternary diagram in Figure 4 . It shows all non-degraded oil samples plot in P zone indicating Paraffinic oils, and biodegraded Kibiro, Nzizi-2 Murram Pit oil seeps plot in PN zone indicating Paraffinic-napthenic oils, and biodegraded Runga and Sonso oil seeps plot in N zone indicating Naphthenic oils. However, the fact that oils are biodegraded implies that the classification as Paraffinicnaphthenic and Naphthenic may be unrealistic.

The GC-FID data are presented in Appendix A2 as raw data, and the following values of n-C₁₅ to n-C₃₄, Pr, Ph and ratios of Pr/Ph, Pr/(Pr + Ph), waxiness, CPI, OEP, and TAR were later screened out for various interpretations and plots to attain specific objectives.

The source rock characteristics (e.g., maturity, source rock lithology) are determined from chemistry of oils using various plots and geochemical interpretive templates as discussed below.

The use of geochemical parameters of sats, aros and NSO + Asph as illustrated, shows that Mputa-1, Mputa-3, Mputa-4, Waraga-1 and Nziz-2 oil has high ratios of saturates to aromatics suggesting maturity, and biodegraded seeps of Kibiro Nzizi-2 Murram Pit Runga and Sonso has low ratios of saturates to aromatics suggesting immaturity ( Tissot & Welte, 1984 ; Echegu, 2013 ).

A plot of ratios of 20S/(20S + 20R) for C₂₇-sterane vs 22S/(22S + 22R) for C₃₁homohopane for all oil samples is indicated in Figure 5 . All oil samples studied plot in a region that indicate high maturity illustrating that the oil samples originated from mature source rock.

A plot of Moretane/Hopane vs Ts/Tm ratios for oil and oil seep samples is indicated in Figure 6 . Except for Kibiro oil seep, most of the samples (Mputa-1, Mputa-3, Mputa-4, Waraga-1 and Nzizi-2) plot in a zone that illustrates derivation from mature source rocks.

The sterane ratio αββ/(αββ + ααα) for C₂₉-Sterane with values 0.67-0.71 suggests oil window maturity for the source rocks ( Seifert & Moldowan, 1986 ). The ratio of Ts/Tm range between 1.37 and 1.54, suggesting that oils are generated from mature source rocks.

On the contrary however, data from αββ/(αββ + ααα) for (C₂₉-Sterane) ranges from 0.2 and 0.27 indicating a derivation from immature source rock.

The disagreement between the two maturity parameters could be as a result of the catalytic effect of siliclastics, that is, iron and aluminium in siliciclastics catalyse the transformation of trisnorhopane to trisnorneohopane ( Waples & Michihara, 1991 ).

The geochemical maturity parameter Ts/(Ts + Tm) reaches equilibrium at 0-0.62 from low maturity to high ( Waples & Machihara, 1991 ; Mackenzie, 1984 ) while the Homohopane maturity parameter 22S/(22S + 22R) for C₃₁-exhibits high maturity at 0.570.62 ( Seifert & Moldowan, 1986 ). For the oils under study, the ratio of Ts/(Ts + Tm) is ranging from 0.580.61 while 22S/(22S + 22R) for C₃₁-homohopane ranges 0.56-0.59. This suggests that the oils and oil seeps were generated from mature source rocks.

A plot of DBT/Phen vs NH/Hop ratios for oil and oil samples is indicated in Figure 7 . All oil and oil seep samples plot in a region that shows derivation of oils from shale source rock deposited in oxic-sub oxic environment.

CPI ratios greater than 1 shows shale source rock and CPI ratios less than 1 suggests carbonate source rock ( Palacas et al., 1984 ; Moldowan et al., 1985 ) and ratios of diasterane/sterane less than 1 are suggestive of carbonate source rock and diasterane/sterane greater than 1 suggests shale source rock ( Mello et al., 1988 ). The CPI and diasterane/sterane ratios amongst the oil samples under study is in the range of 1.091.11 (Table 4.3) and 1.28 - 1.50 respectively. This suggests that oil samples are derived from shale source rock. This statement may not be conclusive since CPI and Pr/Ph are usually influenced by maturity and depositional environment.

The ratio of DBT/Phen under 1 shows shale source rock while Pr/Ph ratio from 1 - 3 suggests shale source rock. On the other hand, Pr/Ph ratios greater than 3 shows shale (coal) source rock and DBT/Phen ratios above 1 indicates carbonate sourcing ( Hughes et al., 1995 ). The ratios of Pr/Ph and DBT/Phen for the oil samples under study range from 2.93 - 3.16 and 0.03 - 0.15, respectively. This suggests that oils are derived from shale source rock with small quantity of coal sediments, however, this may not be conclusive because Pr/Ph ratios are always influenced by depositional environment, and maturity and may not be preserved well.

A plot of dh/29Ts vs diasterane/sterane ratios for oil and oil seep samples is illustrated in Figure 8 . All oil and oil seep samples plot in a zone that suggests shale source rock.

The main aim of this study was to geochemically characterise and classify the oils with the view of inferring the source rock characteristics from the chemistry of oils. In this study, the GC-FID traces and sats/aros ratios were used to assess the biodegradation of oil and oil seep samples as highlighted in Figure 3(a) and Figure 3(b) , Chapter 4. The derived geochemical parameters, interpretive ratios/values and various plots were also used. This chapter discusses the findings of the study.

According to Hakimi et al. (2011) , crude oil samples with sats/aros ratio greater than 1 shows non-degraded crude oil and that if the ratio is less than 1 it suggests biodegraded crude oil. The saturate and aromatic fractions for this study. In reference to this study, oils from Mputa-1, Mputa-3, Mputa-4, Waraga-1 and Nzizi-2 are non-degraded while Kibiro, Nzizi-2, Murram Pit, Runga and Sonso are biodegraded.

Gas chromatograms of saturated fractions from representative crude oil samples suggests non-degradation if there is dominance of n-alkanes with no change in baseline humps and biodegraded if n-alkanes are absent and there is change in baseline humps ( Hakimi et al., 2011 ; Malik, 2012 ). GC-FID traces for Kibiro, Nzizi-2 Murram Pit, Runga and Sonso show these oils are therefore biodegraded. Waraga-1, Mputa-1, Mputa-3, Mputa-4 and Nzizi-2 oils on the other hand have traces of n-C₁₇ & n-C₁₈, and Pr and Ph and with normal baseline without humps. These oils are therefore not biodegraded.

Oil enriched with higher saturates than aromatics, naphthene and NSO is classified as paraffinic high waxy oil type ( Hammad et al., 2015 ). Tissot & Welte (1984) in their research, they observed that crude oil samples with high ratios of saturates to aromatics are paraffinic oils, and crude oil samples with low ratios of aromatics to asphaltenes and NSO are classified as Paraffinic-naphthenic oils. The lowest ratios of asphaltenes and NSO belong to Naphthenic oils. Based on the saturate-aromatics-NSO-asphaltene abundances in the oils studied ( Figure 4 ), Mputa-1, Mputa-3, Mputa-4, Waraga-1, and Nzizi-2 are classified as Paraffinic oils. Runga and Sonso on the other hand are classified as Naphthenic oils, Kibiro and Nzizi-2 Murram Pit are classified as Paraffinic-naphthenic oils. These seeps might have undergone a stage of extensive migration and expulsion which exposes them to microbial activity, in actual sense, if the seeps were preserved at better conditions then, they would have been regarded as paraffinic oils. Consequently, the crude oil of Eastern Lake Albert basin yields commercial paraffinic oil.

The geochemical characterisation of oils was used to infer the source rock characteristics from oil-characterisation covering aspects such as source rock maturity, source rock lithology. It might be apparent as the oil have suffered from biodegradation, thermal alteration and migration effects.

According to Peters et al. (2000) , ratios of saturated to aromatic hydrocarbon components in crude oil increases with increase in maturitiy while polar to asphaltenes ratios decreases with decrease in maturity. This agrees with geochemical parameters highlighted in Figure 4 for the oils under study. The data shows that oils under study, with exception oil seeps, were derived from mature source rocks. The derivation of oil seeps from immature source rocks as suggested by the data may be due to biodegradation, which implies the biomarkers were not preserved well, if preserved, in which case, they could as well be derived from mature source rocks. This maturity status of source rock in the Albertine Graben is also confirmed by Kiconco (2005) .

The maturity of the source rock is determined using the geochemical templates of 20S/(20S + 20R) for C₂₇-sterane and 22S/(22S + 22R) for C₃₁-homohopane highlighted in Figure 5 and ratios of 20S/(20S + 20R) and 22S/(22S + 22R) in the range 0.57 - 0.6 and 0.58 - 0.59 suggesting that studied oil samples are generated at high level of maturity, therefore the oil samples are derived from mature source rock.

Maturity of the source rock was determined using the geochemical interpretive template for Moretane/Hopane and Ts/Tm ( Figure 6 ). The data suggests that non-degraded oils are derived from mature source rocks. This is concurrence with the work of Jarvie et al. (2007) . The biodegraded Kibiro oil seep however, plots in a zone suggesting derivation from immature source rock. Lirong et al. (2004) reported that Kibuku oil seep was derived from an immature source rock. Apparently, oil seeps seem to be derived from immature source rocks, an indication that the seeps are completely different in origin to the nondegraded oils. Perhaps also indicating different sourcing within the basin.

The maturity parameter of αββ/(αββ + ααα) for C₂₉ sterane has an increasing maturity status from 0-0.70 ( Malik, 2012 ; Onojake et al., 2015 ). Ts/Tm ratios greater than 1 suggest mature crude oils ( Sun et al., 2016 ). For the oil samples under investigation, the ratio αββ/(αββ + ααα) for C₂₉ steranes ranges from 0.20-0.27 while Ts/Tm ratio range from 1.37 - 1.54 (Table 4.4) and Ts/(Ts + Tm) ratio range from 0.58 - 0.61 suggesting mature oil and oil seep samples derived from mature source rock concurring to a statement of Sun et al. (2016) that suggests mature source rocks.

In the above plots and interpretative ratios used in determining the maturity status of oil and oil seep samples, it is suggesting that oil samples are generated from mature source rocks and oil seep samples from immature source rocks. This interpretation, however, is conservative given that the oil seeps are biodegraded and therefore the peaks used could be unrealistic. Generation at higher maturity for both oils and oil seepages is implied. This also means that large amount of hydrocarbons could have been delivered by the source rocks.

C29 norhopane abundance can be influenced by the type of organic matter and depositional environment and severe biodegradation can eventually degrade C29 norhopane.

Source rock lithology is inferred using geochemical parameters of DBT/Phen vs NH/Hop highlighted in Figure 7 and dh/29Ts vs diasterane/sterane ( Figure 8 ). Interpretive ratios of CPI, Pr/Ph suggest that oil and oil seep samples are derived from shale source rock. This is concurring with previous work by Kiconco (2005) and Lukaye (2016) , who stressed that the dominant source rock in the Albertine Graben is shale source rock. Shale rocks are known as excellent source rocks, with early maturity characteristics and migration efficiency compared to carbonate source rocks. This, therefore, implies that a significant amount of hydrocarbons could have been generated by the source rocks.

a) The summary of this study is in brief outlined below.

In relation to the above identified problems, the following recommendations have been suggested for further research in the Eastern Lake Albert basin of the Albertine Graben.