Reservoir rock preoperty and hydrocarbon potentieal in the offshore gamtoos and algoa basins, South Africa
- Authors: Mokoele, Salmina Phuti
- Date: 2022-07
- Subjects: Hydrocarbon reservoirs , South Africa -- Gamtoos River , Gamtoos Estuary (South Africa)
- Language: English
- Type: Doctoral theses , text
- Identifier: http://hdl.handle.net/10353/27981 , vital:71409
- Description: Various research methods were employed to evaluate reservoir rock properties and source rock maturity for hydrocarbon potential in the offshore Gamtoos and Algoa basins, including lithostratigraphy, facies analysis, petrography, geophysics, geochemistry and basin modelling. Sedimentary facies were identified in the Gamtoos Basin along with their inferred depositional systems, mainly from the synrift I and II successions. This was also supplemented by lithostratigraphic evaluation of 12 wells across the study area. Facies analysis was applied to describe different rock types with depositional signatures by using the following parameters: grain fabric/texture, primary sedimentary structures, and fossil contents. Different types of lithofacies and biofacies were recorded indicating variations in bioturbation from low to high intensities. The results revealed a total of 15 types of facies from five cores, which were further subdivided into 8 types of sandstones, 3 types of siltstones, 3 types of mudstones and 1 type of conglomerate. Furthermore, five facies associations FA1 to FA5 were recognized from core evaluation: hemipelagite facies association, fine-grained, thinly bedded heterolithic sandstone-mudstone facies association (low-density turbidity flows), medium to coarse grained massive sandstone facies association high-density turbidity flows, debrites hybrid facies association and coarse grained conglomerate facies association. In terms of lithostratigraphic sequence, they correspond with fine- to medium-grained massive sandstone units of the Ta division, horizontal laminated sandstone units of the Tb division, fine to medium grained wavy laminated sandstone units of the Tc division, parallel laminated siltstones intercalated with fine grained ripple and lenticular sandstones of the Tc to Td divisions and fine grained massive, bedded siltstone units of the Te division. Both the Gamtoos and Algoa offshore basins comprise wells with proven source rock presence. Results from geochemical evaluations have revealed the presence of significant quantities of Late Jurassic to Early Cretaceous (Kimmeridgian, Tithonian, Berriasian, Valanginian and Hauterivian) source rock intervals. The wells used for this research intersected a total of 25 source rocks across the various age groups with an average thickness of 70 m. Source rocks with hydrocarbon potentials were intersected at Kimmeridgian, Tithonian, Berriasian, Valanginian and Hauterivian successions. The source rocks indicate good to excellent quality of hydrocarbons with the potential to generate both oil to gas. For example, Tithonian source rock shows a tremendous petroleum generation potential with mostly type II (oil prone) and type II/III (oil to gas prone) kerogen. The data suggests that the Tithonian source rock was mainly deposited in marine depositional settings with planktons being the main source of kerogen. Some of the kerogen could have originated from limited quantities of algae (marine settings) and terrestrial plants. The source rock indicates a potential to generate variable hydrocarbons from oil, wet gas and dry gas. The Kimmeridgian and Tithonian source rocks range from main oil window to post gas mature zone. In the south-eastern part of the offshore Gamtoos Basin, deep marine shale source rocks were deposited between the Kimmeridgian and Tithonian age and these marine conditions continued throughout the synrift stage. The Algoa Basin indicates the deposition of deep-water shale source rocks resulting from a transgression period. The Berriasian source rock indicates a range in maturity from the early oil to gas windows in the Gamtoos graben between 126 Ma and present day. The source rock further shows a maximum transformation ratio of 100 percent at well Ha-D1 in the Gamtoos Basin. The Valanginian source rock indicates a range in maturity from early to late oil windows in the Algoa Basin with extremely low rates of transformation at a maximum of 24.67 percentage at well Hb-B1. The Hauterivian source rock dominantly plots within the early to main oil windows with vitrinite values between 0.6 and 0.8 percent. Results obtained from this research indicate the presence of moderate to good quality source rocks from the Kimmeridgian, Tithonian, Berriasian, Valanginian and Hauterivian. Majority of the source rocks have type III kerogen which is most likely to generate gas. The study area shows the presence of good quality source rocks with good petroleum generation potentials. The source rocks also show the ability to generate and expel hydrocarbons. The deeper sections of the grabens indicate high maturity levels with source rocks dominantly in the gas and late oil windows while the flanks are indicative of lower maturity stages between early and main oil windows. The best source rocks were mainly intersected and modelled from the synrift section while the upper transitional to drift sections indicate good quality reservoir rocks. The upper sections of the study area show a tremendous improvement in the quality of the reservoirs with porosity levels recorded to be up to 26 percent. The porosity levels increase up to 17 percent at well Ha-B2. This generally improved the potential for good reservoirs in the area from what has been intersected by the wells to the entire study area with the presence of effective traps and seals. The influence of hydrothermal alteration and chlorite cementation is quite low at these shallower sequences which further improved the quality of these reservoirs. Some of the sandstones intersected from the synrift sections range from very fine to coarse grained in texture with very low permeability and porosity due to extensive carbonate cementation, and also affected by hydrothermal alteration resulted from the extensive faulting in the area. , Thesis (PhD) -- Faculty of Science and Agriculture, 2022
- Full Text:
- Authors: Mokoele, Salmina Phuti
- Date: 2022-07
- Subjects: Hydrocarbon reservoirs , South Africa -- Gamtoos River , Gamtoos Estuary (South Africa)
- Language: English
- Type: Doctoral theses , text
- Identifier: http://hdl.handle.net/10353/27981 , vital:71409
- Description: Various research methods were employed to evaluate reservoir rock properties and source rock maturity for hydrocarbon potential in the offshore Gamtoos and Algoa basins, including lithostratigraphy, facies analysis, petrography, geophysics, geochemistry and basin modelling. Sedimentary facies were identified in the Gamtoos Basin along with their inferred depositional systems, mainly from the synrift I and II successions. This was also supplemented by lithostratigraphic evaluation of 12 wells across the study area. Facies analysis was applied to describe different rock types with depositional signatures by using the following parameters: grain fabric/texture, primary sedimentary structures, and fossil contents. Different types of lithofacies and biofacies were recorded indicating variations in bioturbation from low to high intensities. The results revealed a total of 15 types of facies from five cores, which were further subdivided into 8 types of sandstones, 3 types of siltstones, 3 types of mudstones and 1 type of conglomerate. Furthermore, five facies associations FA1 to FA5 were recognized from core evaluation: hemipelagite facies association, fine-grained, thinly bedded heterolithic sandstone-mudstone facies association (low-density turbidity flows), medium to coarse grained massive sandstone facies association high-density turbidity flows, debrites hybrid facies association and coarse grained conglomerate facies association. In terms of lithostratigraphic sequence, they correspond with fine- to medium-grained massive sandstone units of the Ta division, horizontal laminated sandstone units of the Tb division, fine to medium grained wavy laminated sandstone units of the Tc division, parallel laminated siltstones intercalated with fine grained ripple and lenticular sandstones of the Tc to Td divisions and fine grained massive, bedded siltstone units of the Te division. Both the Gamtoos and Algoa offshore basins comprise wells with proven source rock presence. Results from geochemical evaluations have revealed the presence of significant quantities of Late Jurassic to Early Cretaceous (Kimmeridgian, Tithonian, Berriasian, Valanginian and Hauterivian) source rock intervals. The wells used for this research intersected a total of 25 source rocks across the various age groups with an average thickness of 70 m. Source rocks with hydrocarbon potentials were intersected at Kimmeridgian, Tithonian, Berriasian, Valanginian and Hauterivian successions. The source rocks indicate good to excellent quality of hydrocarbons with the potential to generate both oil to gas. For example, Tithonian source rock shows a tremendous petroleum generation potential with mostly type II (oil prone) and type II/III (oil to gas prone) kerogen. The data suggests that the Tithonian source rock was mainly deposited in marine depositional settings with planktons being the main source of kerogen. Some of the kerogen could have originated from limited quantities of algae (marine settings) and terrestrial plants. The source rock indicates a potential to generate variable hydrocarbons from oil, wet gas and dry gas. The Kimmeridgian and Tithonian source rocks range from main oil window to post gas mature zone. In the south-eastern part of the offshore Gamtoos Basin, deep marine shale source rocks were deposited between the Kimmeridgian and Tithonian age and these marine conditions continued throughout the synrift stage. The Algoa Basin indicates the deposition of deep-water shale source rocks resulting from a transgression period. The Berriasian source rock indicates a range in maturity from the early oil to gas windows in the Gamtoos graben between 126 Ma and present day. The source rock further shows a maximum transformation ratio of 100 percent at well Ha-D1 in the Gamtoos Basin. The Valanginian source rock indicates a range in maturity from early to late oil windows in the Algoa Basin with extremely low rates of transformation at a maximum of 24.67 percentage at well Hb-B1. The Hauterivian source rock dominantly plots within the early to main oil windows with vitrinite values between 0.6 and 0.8 percent. Results obtained from this research indicate the presence of moderate to good quality source rocks from the Kimmeridgian, Tithonian, Berriasian, Valanginian and Hauterivian. Majority of the source rocks have type III kerogen which is most likely to generate gas. The study area shows the presence of good quality source rocks with good petroleum generation potentials. The source rocks also show the ability to generate and expel hydrocarbons. The deeper sections of the grabens indicate high maturity levels with source rocks dominantly in the gas and late oil windows while the flanks are indicative of lower maturity stages between early and main oil windows. The best source rocks were mainly intersected and modelled from the synrift section while the upper transitional to drift sections indicate good quality reservoir rocks. The upper sections of the study area show a tremendous improvement in the quality of the reservoirs with porosity levels recorded to be up to 26 percent. The porosity levels increase up to 17 percent at well Ha-B2. This generally improved the potential for good reservoirs in the area from what has been intersected by the wells to the entire study area with the presence of effective traps and seals. The influence of hydrothermal alteration and chlorite cementation is quite low at these shallower sequences which further improved the quality of these reservoirs. Some of the sandstones intersected from the synrift sections range from very fine to coarse grained in texture with very low permeability and porosity due to extensive carbonate cementation, and also affected by hydrothermal alteration resulted from the extensive faulting in the area. , Thesis (PhD) -- Faculty of Science and Agriculture, 2022
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Characterization of sandstone reservoirs and hydrocarbon generation potential of selected four wells in the Pletmos basin, offshore South Africa
- Moloi, Busiswa https://orcid.org/0000-0001-6815-4901
- Authors: Moloi, Busiswa https://orcid.org/0000-0001-6815-4901
- Date: 2021-06
- Subjects: Hydrocarbon reservoirs
- Language: English
- Type: Master's theses , text
- Identifier: http://hdl.handle.net/10353/22512 , vital:52387
- Description: This study focused on the use of data from four wells (Ga-M1, Ga-S1, Ga-Z1, and Gb-J1) comprises of the Late Jurassic to Early Cretaceous shallow marine clastic sandstones consisting of wildcat wells located in Block 11 of the Pletmos Basin, a sub-basin of the Southern Outeniqua Basin, south offshore South Africa. This research evaluates the hydrocarbon potential in the Pletmos Basin by integrating core and well log data to characterize the source and reservoir rock potential. The methods implemented consist of a mineralogical and petrological analysis of about 300 thin section slides from four wells were studied. Stratigraphic profile computation from core logging, geochemistry analysis focusing on total organic carbon (TOC), geophysical wireline logs, conventional core analysis, geological well reports, and petrophysical analysis (water saturation, porosity, permeability, and volume of clay) were done using Interactive Petrophysics software. The different datasets were used to delineate how the mineralogy, total organic carbon content, poro-perm properties, fluid saturation, and volume of clay impact the hydrocarbon production potential. The evaluated sandstones have depths ranging from 2523.9 m to 3397.2 m with varying thickness depending on the position of the well. The results indicate that the study area consists of shallow marine clastic sandstones with sparse siltstones and mudstone that are fine-grained to silty in texture. The sedimentary sequence is characterized by moderate to intense bioturbation. Depositional environment was in a reducing condition indicated by plenty of glauconites. The tight fine-grained sandstones have low porosity values ranging from 4.5% to 13.8% in the selected intervals. The low porosity values may have been caused by the quartz cement that is observed from the thin sections. Low permeability values ranging from 0 mD to 0.16 mD are present throughout the studied wells caused by calcite cement and clay matrix. Source rock in the studied wells have inferior TOC values ranging from 0.31 wt% to 0.51 wt%. The van Krevelen indicates that the analysed samples have very low hydrogen index (HI) values and are consistent with Type III Kerogen (gas prone). A total of six reservoirs were identified. For well Ga-M1, one reservoir interval (2988.2 m – 30281 m) was selected and is located at BCII formation and was classified as a nonproducing reservoir due to its high water saturation content of 94.2%, even though it has an average porosity of 10.6%. Two reservoirs were selected for well Ga-S1, reservoir one (3026.3 m – 3107.7 m) is located within the 13AT1 formation and was classified as a producing reservoir with an average porosity of 11.9%, water saturation of 38.3%, and volume of clay of 29.5%. Reservoir 2 (3380.7 m – 3397.2 m) and the reservoirs (2970.20 m – 2993.0 m and 3006.80 m – 3049.50 m) from well Ga-Z1 located between the 9AT1 – BCVI formations were classified as non-reservoirs. One selected reservoir from well Gb-J1 had promising gas shows with an average porosity of 19%, water saturation value of 34.8%, and volume of shale of 33.1%. However, well Ga-S1 has a large interval with hydrocarbon potential compared to the well Gb-J1. Results indicate that the absence of hydrocarbon accumulation may result from non-effective seals due to the silty texture of the reservoir sandstones. Also, the presence of calcareous cement, clay minerals, and the argillaceous matrix reduce the porosity and permeability characteristics. To better understand the hydrocarbon potential of the Pletmos Basin, 3D seismic data is recommended to perform seismic well tie analysis for correlation between well log and seismic data to understand the basin‟s potential better. , Thesis (MSc) -- Faculty of Science and Agriculture, 2021
- Full Text:
- Authors: Moloi, Busiswa https://orcid.org/0000-0001-6815-4901
- Date: 2021-06
- Subjects: Hydrocarbon reservoirs
- Language: English
- Type: Master's theses , text
- Identifier: http://hdl.handle.net/10353/22512 , vital:52387
- Description: This study focused on the use of data from four wells (Ga-M1, Ga-S1, Ga-Z1, and Gb-J1) comprises of the Late Jurassic to Early Cretaceous shallow marine clastic sandstones consisting of wildcat wells located in Block 11 of the Pletmos Basin, a sub-basin of the Southern Outeniqua Basin, south offshore South Africa. This research evaluates the hydrocarbon potential in the Pletmos Basin by integrating core and well log data to characterize the source and reservoir rock potential. The methods implemented consist of a mineralogical and petrological analysis of about 300 thin section slides from four wells were studied. Stratigraphic profile computation from core logging, geochemistry analysis focusing on total organic carbon (TOC), geophysical wireline logs, conventional core analysis, geological well reports, and petrophysical analysis (water saturation, porosity, permeability, and volume of clay) were done using Interactive Petrophysics software. The different datasets were used to delineate how the mineralogy, total organic carbon content, poro-perm properties, fluid saturation, and volume of clay impact the hydrocarbon production potential. The evaluated sandstones have depths ranging from 2523.9 m to 3397.2 m with varying thickness depending on the position of the well. The results indicate that the study area consists of shallow marine clastic sandstones with sparse siltstones and mudstone that are fine-grained to silty in texture. The sedimentary sequence is characterized by moderate to intense bioturbation. Depositional environment was in a reducing condition indicated by plenty of glauconites. The tight fine-grained sandstones have low porosity values ranging from 4.5% to 13.8% in the selected intervals. The low porosity values may have been caused by the quartz cement that is observed from the thin sections. Low permeability values ranging from 0 mD to 0.16 mD are present throughout the studied wells caused by calcite cement and clay matrix. Source rock in the studied wells have inferior TOC values ranging from 0.31 wt% to 0.51 wt%. The van Krevelen indicates that the analysed samples have very low hydrogen index (HI) values and are consistent with Type III Kerogen (gas prone). A total of six reservoirs were identified. For well Ga-M1, one reservoir interval (2988.2 m – 30281 m) was selected and is located at BCII formation and was classified as a nonproducing reservoir due to its high water saturation content of 94.2%, even though it has an average porosity of 10.6%. Two reservoirs were selected for well Ga-S1, reservoir one (3026.3 m – 3107.7 m) is located within the 13AT1 formation and was classified as a producing reservoir with an average porosity of 11.9%, water saturation of 38.3%, and volume of clay of 29.5%. Reservoir 2 (3380.7 m – 3397.2 m) and the reservoirs (2970.20 m – 2993.0 m and 3006.80 m – 3049.50 m) from well Ga-Z1 located between the 9AT1 – BCVI formations were classified as non-reservoirs. One selected reservoir from well Gb-J1 had promising gas shows with an average porosity of 19%, water saturation value of 34.8%, and volume of shale of 33.1%. However, well Ga-S1 has a large interval with hydrocarbon potential compared to the well Gb-J1. Results indicate that the absence of hydrocarbon accumulation may result from non-effective seals due to the silty texture of the reservoir sandstones. Also, the presence of calcareous cement, clay minerals, and the argillaceous matrix reduce the porosity and permeability characteristics. To better understand the hydrocarbon potential of the Pletmos Basin, 3D seismic data is recommended to perform seismic well tie analysis for correlation between well log and seismic data to understand the basin‟s potential better. , Thesis (MSc) -- Faculty of Science and Agriculture, 2021
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Sedimentology, reservoir properties and hydrocarbon potential of the southern Bredasdorp Basin, offshore of the Western Cape Province, South Africa
- Authors: Baiyegunhi, Temitope Love
- Date: 2021-05
- Subjects: Sediments (Geology) , Hydrocarbon reservoirs
- Language: English
- Type: Doctoral theses , text
- Identifier: http://hdl.handle.net/10353/20753 , vital:46546
- Description: The Bredasdorp Basin has become the focus for exploration activity (i.e., seismic exploration and drilling) since the discovery of gas-condensate and oil reservoirs in the early 1980s. The basin has proven hydrocarbon reserves and potential for future discoveries. However, uncertainty about the sedimentological and petrographic characteristics, reservoir qualities, thermal maturity and hydrocarbon potential of the source/reservoir rocks has hindered further exploration, particularly in the southern part of the basin. To date, this part of the basin remains unexplored and partially understood with respect to petroleum systems evolution when compared to the central and northern parts of the basin. To fill the research gaps, exploration wells E-AH1, E-AJ1, E-BA1, E-BB1 and E-D3 were investigated so as to unravel the petrographic characteristics, depositional processes and paleoenvironment, tectonic provenance, paleoweathering, hydrocarbon potential, thermal maturity, diagenetic characterisitcs and reservoir qualities of the southern Bredasdorp Basin. The grain size textural parameters revealed that the southern Bredasdorp Basin sandstones are unimodal, predominantly fine-grained, moderately well sorted, mesokurtic and near-symmetrical. The bivariate plots of grain size textural parameters indicate that the depositional environments had been influenced mainly by river/beach/coastal dune conditions. The linear discriminate functions (LDF) diagrams show that the sediments are turbidity current deposits in a shallow marine environment. The Passega diagram revealed that the studied sandstones were mainly deposited by traction currents and beach process. In addition, the grain size log-probability curves and Passega diagram show the predominance of saltation and suspension modes of sediment transportation. Based on the inter-relationship of the various statistical parameters, it is deduced that the southern Bredasdorp Basin are mainly shallow marine deposits with signature of beach and coastal river processes. Based on the lithofacies analysis of the southern Bredasdorp Basin borehole cores, thirteen lithofacies were identified and grouped into six facies associations (FAs). The facies associations are: matrix supported conglomerate and massive sandstone (FA 1), ripple cross laminated, trough cross bedded and bioturbated sandstone (FA 2), massive sandstone with mudstone and shale interbeds (FA 3), alternating laminated to interbedded sandstone/siltstone and mudstone (FA 4), massive mudstone with minor interlamination of clay-rich sandstones and siltstone (FA 5), and carbonaceous laminated shale and mudstone with occasional siltstone laminae (FA 6). Facies associations FA1, FA2, FA3, FA4, FA5 and FA6 are interpreted as submarine channel-fills, submarine channel-levee, submarine sheet lobe, submarine lobe fring/overflow, basin plain deposits and deep sea floor/basin plain deposits, respectively. Sedimentological evidences from lithofacies interpretation revealed shallow marine environment as the main depositional environment, with minor contribution from the deep marine environment. Petrographic studies show that the southern Bredasdorp Basin sandstones chiefly consist of quartz (52.2–68.0percent), feldspar (10.0–18.0percent), and lithic fragments (5.0–10.2percent). The modal composition analysis revealed that the sandstones could be classified as subarkosic arenite and lithic arkose. The provenance ternary diagrams revealed that the rocks are mainly of continental block provenances (stable shields and basement uplifted areas) and complemented by recycled sands from an associated platform. The tectonic provenance studies show that the sandstones are typically rift-derived arenites and have undergone long-distance transport from the source area along the rift. In the regional context of the evolution of the Bredasdorp Basin, the results suggested that the basin developed on a passive rift setting (trailing edge) of the stable continental margins. The provenance discrimination diagrams based on major oxide geochemistry revealed that the sandstones are mainly of quartzose sedimentary provenance, while the mudrocks are of quartzose sedimentary and intermediate igneous provenances. The discrimination diagrams indicate that the southern Bredasdorp Basin sediments were mostly derived from a cratonic interior or recycled orogen. The bivariate plots of TiO2 versus Ni, TiO2 against Zr and La/Th versus Hf as well as the ternary diagrams of V–Ni–Th×10 suggest that the mudrocks and sandstones were derived from felsic igneous rocks. The tectonic setting discrimination diagrams support passive-active continental margin setting of the provenance. Chemical index of alteration (CIA) indices observed in the sandstones suggest that their source area underwent low to moderate degree of chemical weathering. However, the mudrocks have high CIA indices suggesting that the source area underwent more intense chemical weathering, possibly due to climatic and/or tectonic variations. The organic geochemistry results show that these rocks have total organic carbon, TOC contents ranging from 0.14 to 7.03 wt.percent. The hydrogen index (HI), oxygen index (OI), and hydrocarbon index (S2/S3) values vary between 24–263 mg HC/g TOC, 4–78 mg CO2/g TOC, and 0.01–18 mgHC/mgCO2 TOC, respectively, indicating predominantly Type III and IV kerogen with a minor amount of mixed Type II/III kerogen. The mean vitrinite reflectance values vary from 0.60–1.20percent, indicating that the samples are in the oil-generation window. The Tmax and PI values are consistent with the mean vitrinite reflectance values, indicating that the southern Bredasdorp Basin source rocks have entered the oil window and are considered as effective source rocks in the southern Bredasdorp Basin. The hydrocarbon genetic potential (SP), normalized oil content (NOC) and production index (PI) values all indicate poor to fair hydrocarbon generative potential. The main diagenetic processes that have affected the reservoir quality of the southern Bredasdorp Basin rocks are cementation by authigenic clay, carbonate and silica, growth of authigenic glauconite, dissolution of minerals and load compaction. These aforementioned diagenetic processes act differently in each borehole and at different depths. The influence of cementation and compaction is complex with no particular pattern with increasing depth, suggesting that diagenesis is the main challenge to reservoir characterization in the southern Bredasdorp Basin. The clays in the sandstones act as pore choking cement, which reduces porosity and permeability of the reservoir rocks. Reservoir quality of the sandstones has been improved to various extents due to the development of secondary porosity as a result of partial to complete dissolution of early calcite cement and some detrital grains (feldspars) and also affected by grain fracturing. The scattered plots of porosity and permeability versus cement+clays show good inverse correlations, suggesting that the reservoir quality is mainly controlled by cementation and authigenic clays. Based on the diagenetic study, it can be inferred that the potential reservoir quality of the southern Bredasdorp Basin sandstones is poor-moderate. , Thesis (PhD) -- Faculty of Science and Agriculture, 2021
- Full Text:
- Authors: Baiyegunhi, Temitope Love
- Date: 2021-05
- Subjects: Sediments (Geology) , Hydrocarbon reservoirs
- Language: English
- Type: Doctoral theses , text
- Identifier: http://hdl.handle.net/10353/20753 , vital:46546
- Description: The Bredasdorp Basin has become the focus for exploration activity (i.e., seismic exploration and drilling) since the discovery of gas-condensate and oil reservoirs in the early 1980s. The basin has proven hydrocarbon reserves and potential for future discoveries. However, uncertainty about the sedimentological and petrographic characteristics, reservoir qualities, thermal maturity and hydrocarbon potential of the source/reservoir rocks has hindered further exploration, particularly in the southern part of the basin. To date, this part of the basin remains unexplored and partially understood with respect to petroleum systems evolution when compared to the central and northern parts of the basin. To fill the research gaps, exploration wells E-AH1, E-AJ1, E-BA1, E-BB1 and E-D3 were investigated so as to unravel the petrographic characteristics, depositional processes and paleoenvironment, tectonic provenance, paleoweathering, hydrocarbon potential, thermal maturity, diagenetic characterisitcs and reservoir qualities of the southern Bredasdorp Basin. The grain size textural parameters revealed that the southern Bredasdorp Basin sandstones are unimodal, predominantly fine-grained, moderately well sorted, mesokurtic and near-symmetrical. The bivariate plots of grain size textural parameters indicate that the depositional environments had been influenced mainly by river/beach/coastal dune conditions. The linear discriminate functions (LDF) diagrams show that the sediments are turbidity current deposits in a shallow marine environment. The Passega diagram revealed that the studied sandstones were mainly deposited by traction currents and beach process. In addition, the grain size log-probability curves and Passega diagram show the predominance of saltation and suspension modes of sediment transportation. Based on the inter-relationship of the various statistical parameters, it is deduced that the southern Bredasdorp Basin are mainly shallow marine deposits with signature of beach and coastal river processes. Based on the lithofacies analysis of the southern Bredasdorp Basin borehole cores, thirteen lithofacies were identified and grouped into six facies associations (FAs). The facies associations are: matrix supported conglomerate and massive sandstone (FA 1), ripple cross laminated, trough cross bedded and bioturbated sandstone (FA 2), massive sandstone with mudstone and shale interbeds (FA 3), alternating laminated to interbedded sandstone/siltstone and mudstone (FA 4), massive mudstone with minor interlamination of clay-rich sandstones and siltstone (FA 5), and carbonaceous laminated shale and mudstone with occasional siltstone laminae (FA 6). Facies associations FA1, FA2, FA3, FA4, FA5 and FA6 are interpreted as submarine channel-fills, submarine channel-levee, submarine sheet lobe, submarine lobe fring/overflow, basin plain deposits and deep sea floor/basin plain deposits, respectively. Sedimentological evidences from lithofacies interpretation revealed shallow marine environment as the main depositional environment, with minor contribution from the deep marine environment. Petrographic studies show that the southern Bredasdorp Basin sandstones chiefly consist of quartz (52.2–68.0percent), feldspar (10.0–18.0percent), and lithic fragments (5.0–10.2percent). The modal composition analysis revealed that the sandstones could be classified as subarkosic arenite and lithic arkose. The provenance ternary diagrams revealed that the rocks are mainly of continental block provenances (stable shields and basement uplifted areas) and complemented by recycled sands from an associated platform. The tectonic provenance studies show that the sandstones are typically rift-derived arenites and have undergone long-distance transport from the source area along the rift. In the regional context of the evolution of the Bredasdorp Basin, the results suggested that the basin developed on a passive rift setting (trailing edge) of the stable continental margins. The provenance discrimination diagrams based on major oxide geochemistry revealed that the sandstones are mainly of quartzose sedimentary provenance, while the mudrocks are of quartzose sedimentary and intermediate igneous provenances. The discrimination diagrams indicate that the southern Bredasdorp Basin sediments were mostly derived from a cratonic interior or recycled orogen. The bivariate plots of TiO2 versus Ni, TiO2 against Zr and La/Th versus Hf as well as the ternary diagrams of V–Ni–Th×10 suggest that the mudrocks and sandstones were derived from felsic igneous rocks. The tectonic setting discrimination diagrams support passive-active continental margin setting of the provenance. Chemical index of alteration (CIA) indices observed in the sandstones suggest that their source area underwent low to moderate degree of chemical weathering. However, the mudrocks have high CIA indices suggesting that the source area underwent more intense chemical weathering, possibly due to climatic and/or tectonic variations. The organic geochemistry results show that these rocks have total organic carbon, TOC contents ranging from 0.14 to 7.03 wt.percent. The hydrogen index (HI), oxygen index (OI), and hydrocarbon index (S2/S3) values vary between 24–263 mg HC/g TOC, 4–78 mg CO2/g TOC, and 0.01–18 mgHC/mgCO2 TOC, respectively, indicating predominantly Type III and IV kerogen with a minor amount of mixed Type II/III kerogen. The mean vitrinite reflectance values vary from 0.60–1.20percent, indicating that the samples are in the oil-generation window. The Tmax and PI values are consistent with the mean vitrinite reflectance values, indicating that the southern Bredasdorp Basin source rocks have entered the oil window and are considered as effective source rocks in the southern Bredasdorp Basin. The hydrocarbon genetic potential (SP), normalized oil content (NOC) and production index (PI) values all indicate poor to fair hydrocarbon generative potential. The main diagenetic processes that have affected the reservoir quality of the southern Bredasdorp Basin rocks are cementation by authigenic clay, carbonate and silica, growth of authigenic glauconite, dissolution of minerals and load compaction. These aforementioned diagenetic processes act differently in each borehole and at different depths. The influence of cementation and compaction is complex with no particular pattern with increasing depth, suggesting that diagenesis is the main challenge to reservoir characterization in the southern Bredasdorp Basin. The clays in the sandstones act as pore choking cement, which reduces porosity and permeability of the reservoir rocks. Reservoir quality of the sandstones has been improved to various extents due to the development of secondary porosity as a result of partial to complete dissolution of early calcite cement and some detrital grains (feldspars) and also affected by grain fracturing. The scattered plots of porosity and permeability versus cement+clays show good inverse correlations, suggesting that the reservoir quality is mainly controlled by cementation and authigenic clays. Based on the diagenetic study, it can be inferred that the potential reservoir quality of the southern Bredasdorp Basin sandstones is poor-moderate. , Thesis (PhD) -- Faculty of Science and Agriculture, 2021
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