The Lynedoch field is located on the west flank of the Calder Graben in the north-eastern Bonaparte Basin, Australia. The data from the wells Lynedoch 1 and Lynedoch 2 and Seismic Line N11809 were used to reconstruct ...The Lynedoch field is located on the west flank of the Calder Graben in the north-eastern Bonaparte Basin, Australia. The data from the wells Lynedoch 1 and Lynedoch 2 and Seismic Line N11809 were used to reconstruct the burial and thermal histories and evaluate the hydrocarbon generated and expelled from the Jurassic to Early Cretaceous source rocks of the study area. Basin Mod 1-D and 2-D softwares were used for modeling. The Upper Jurassic Cleia (Lower Frigate) and Lower Cretaceous Echuca Shoals formations source rocks in the well Lynedoch 1 were a fair-to-good source richness with poor hydrocarbon generating potential, showing kerogen type III and gas prone. The Middle Jurassic Plover Formation source rock in the well Lynedoch 2 was a good organic matter richness with poor hydrocarbon generative potential, the late Middle Jurassic (Callovian) Elang Formation source rock in the same well was a fair source rock with poor hydrocarbon generation potential, and the Lower Cretaceous Echuca Shoals Formation source rock in the same well was a fair-to-very good organic richness with poor-to-fair hydrocarbon generating potential, gas prone with kerogen type III, and reaching wet gas window at present day. These previous formations of the both wells generated oil at the Late Cretaceous and gas at the Early Neogene. But, only Echuca Shoals Formation source rock in the well Lynedoch 2 was able to expelled hydrocarbon at the Middle Paleogene and continued up to present day. This Formation represents fair to slightly good potential source rock in the Lynedoch field.展开更多
The Sahul Platform where the Sunset-Loxton Shoals and Chuditch gas fields were discovered is located between the Timor Trough to the north and the Malita Graben to the south. These areas are located respectively 440 k...The Sahul Platform where the Sunset-Loxton Shoals and Chuditch gas fields were discovered is located between the Timor Trough to the north and the Malita Graben to the south. These areas are located respectively 440 km and 380 km northwest of Darwin in the northern Bonaparte Basin, Australia. Based on the structural evolution of the northern Bonaparte Basin, data from the wells Loxton Shoals 1, Sunset 1 and Chuditch 1 in the Sahul Platform and Heron 1 in the Malita Graben depocentre, and the Seismic Line N11606 were used to clarify the geological conditions and reconstruct the hydrocarbon accumulation processes in the study area. BasinMod 1-D, 2-D, and 3-D software was used for modeling. The Plover Formation source rock was a poor-to-good hydrocarbon generative potential and reached the middle to late mature oil window in the Sunset-Loxton Shoals field whereas in the Chuditch field, it was an overall fair-to-good hydrocarbon generative potential, and attained the Late mature oil window. The Flamingo, and the Echuca Shoals formations source rocks in the same field were a fair and good hydrocarbon generation potential respectively, and both reached mid-mature oil window. In the Malita Graben depocentre, the Petrel (Frigate) and the Echuca Shoals formations source rocks were a poor-to-very good hydrocarbon generating potential, and had attained wet gas window at the present day. The analyses of organic matter showed that the source rocks in the study area and Malita Graben were gas prone with kerogen types II2 & III and III predominantly. The Middle Jurassic Plover Formation sandstone reservoir in the Sunset-Loxton field was a poor-to-very good quality and potential for gas beds, and it was a very poor-to-very good quality and potential for gas beds in the Chuditch field. The intensities of gas generation and expulsion were more than of oil ones either in the Sahul Platform or in the Malita Graben. The Plover, Petrel (Frigate) and Echuca Shoals formations source rocks in the wells Chuditch 1 and Heron 1, except for the Flamingo Formation in the well Chuditch 1, had higher gas and oil expelling efficiencies than the Plover Formation source rock of the wells in the Sunset-Loxton Shoals field. The hydrocarbon migrated mainly from the Upper Jurassic Frigate Shale source rock in the Malita Graben depocentre (structurally lower) to the Plover Formation sandstone reservoir in the Sunset-Loxton Shoals field during the Late Cretaceous at 66 Ma. In the Chuditch field, the hydrocarbon migration to the Plover Formation sandstone reservoir was initiated during the Late Miocene at 7.5 Ma from the Middle Jurassic Plover Formation source rock in the well Chuditch 1. Nowadays, the main migration pathways are from the southeastward and southward of the Sunset-Loxton Shoals field, and from southward and eastward of the Chuditch field, precisely from the hydrocarbon source kitchens of the Malita Graben depocentre. The traps in the Sahul Platform have been effective to receive the migrated hydrocarbon.展开更多
The Malita Graben is located in the northern Bonaparte Basin, between the Sahul Platform to the northwest and the Petrel Sub-basin and Darwin Shelf to the south. The wells Beluga 1, Heron 1, Evans Shoal 1, Evans Shoal...The Malita Graben is located in the northern Bonaparte Basin, between the Sahul Platform to the northwest and the Petrel Sub-basin and Darwin Shelf to the south. The wells Beluga 1, Heron 1, Evans Shoal 1, Evans Shoal 2 and Seismic Line N11805 are selected to determine the thermal history and potential of hydrocarbon generated from the Plover, Elang, Frigate Shale (Cleia and Flamingo), and Echuca Shoals formations source rocks. The modeling was performed by using Basin Mod 1-D and 2-D techniques. The model results show that the geothermal gradients range from 3.05 to 4.05°C/100 m with an average of 3.75°C/100 m and present day heat flow values from 46.23 to 61.99 mW/m2 with an average of 56.29 mW/m2. The highest geothermal gradient and present-day heat flow values occurred on a terrace north of the Malita Graben. These most likely indicate that hot fluids are currently variably migrating into this structure. The lower geothermal gradient and heat flow values have been modeled in the southeast sites in the well Beluga 1. The northern Bonaparte Basin experienced several deformation phases including lithospheric thinning;hence, heat flow is expected to vary over the geological history of the basin. The higher paleo-heat flow values changing from 83.54 to 112.01 mW/m2 with an average of 101.71 mW/m2 during Jurassic rift event (syn-rift) were sufficient for source rocks maturation and hydrocarbon generation during Cretaceous post-breakup sequence (post-rift) in the study area. The Tuatara (Upper Frigate Shale) Formation source rock with type II & III kerogen dominantly showing mixed oil- and gas-prone, and Plover Formation with type III and gas prone have never reached the peak mature oil window in the well Beluga 1. This area indicates that the maturity of source rocks is low and considered to be from poor-to-good organic richness with poor-to-fair potential for hydrocarbons generation. The post mature Cleia (Lower Frigate Shale) and Echuca Shoals formations source rocks in the well Evans Shoal 1 and an early mature oil window Echuca Shoals formation source rock in the well Evans Shoal 2, characterized by type III kerogen dominantly showing gasprone are a fair-to-very good source richness with poor potential for hydrocarbons generation. The low to high maturity of Echuca Shoals and Petrel (Frigate Shale) formations source rocks in the well Heron 1, Plover Formation source rock in the Evans Shoal 1 well, and Cleia (Lower Frigate Shale) and Plover formations in the well Evans Shoal 2, showing gas-prone with type III and II & III kerogens predominantly, have reached the late mature oil and wet gas generation stages at present day. These last five formations source rocks are seen from poor-to-very good organic richness with poor-to-very good potential for hydrocarbons generation in the Malita Graben.展开更多
文摘The Lynedoch field is located on the west flank of the Calder Graben in the north-eastern Bonaparte Basin, Australia. The data from the wells Lynedoch 1 and Lynedoch 2 and Seismic Line N11809 were used to reconstruct the burial and thermal histories and evaluate the hydrocarbon generated and expelled from the Jurassic to Early Cretaceous source rocks of the study area. Basin Mod 1-D and 2-D softwares were used for modeling. The Upper Jurassic Cleia (Lower Frigate) and Lower Cretaceous Echuca Shoals formations source rocks in the well Lynedoch 1 were a fair-to-good source richness with poor hydrocarbon generating potential, showing kerogen type III and gas prone. The Middle Jurassic Plover Formation source rock in the well Lynedoch 2 was a good organic matter richness with poor hydrocarbon generative potential, the late Middle Jurassic (Callovian) Elang Formation source rock in the same well was a fair source rock with poor hydrocarbon generation potential, and the Lower Cretaceous Echuca Shoals Formation source rock in the same well was a fair-to-very good organic richness with poor-to-fair hydrocarbon generating potential, gas prone with kerogen type III, and reaching wet gas window at present day. These previous formations of the both wells generated oil at the Late Cretaceous and gas at the Early Neogene. But, only Echuca Shoals Formation source rock in the well Lynedoch 2 was able to expelled hydrocarbon at the Middle Paleogene and continued up to present day. This Formation represents fair to slightly good potential source rock in the Lynedoch field.
文摘The Sahul Platform where the Sunset-Loxton Shoals and Chuditch gas fields were discovered is located between the Timor Trough to the north and the Malita Graben to the south. These areas are located respectively 440 km and 380 km northwest of Darwin in the northern Bonaparte Basin, Australia. Based on the structural evolution of the northern Bonaparte Basin, data from the wells Loxton Shoals 1, Sunset 1 and Chuditch 1 in the Sahul Platform and Heron 1 in the Malita Graben depocentre, and the Seismic Line N11606 were used to clarify the geological conditions and reconstruct the hydrocarbon accumulation processes in the study area. BasinMod 1-D, 2-D, and 3-D software was used for modeling. The Plover Formation source rock was a poor-to-good hydrocarbon generative potential and reached the middle to late mature oil window in the Sunset-Loxton Shoals field whereas in the Chuditch field, it was an overall fair-to-good hydrocarbon generative potential, and attained the Late mature oil window. The Flamingo, and the Echuca Shoals formations source rocks in the same field were a fair and good hydrocarbon generation potential respectively, and both reached mid-mature oil window. In the Malita Graben depocentre, the Petrel (Frigate) and the Echuca Shoals formations source rocks were a poor-to-very good hydrocarbon generating potential, and had attained wet gas window at the present day. The analyses of organic matter showed that the source rocks in the study area and Malita Graben were gas prone with kerogen types II2 & III and III predominantly. The Middle Jurassic Plover Formation sandstone reservoir in the Sunset-Loxton field was a poor-to-very good quality and potential for gas beds, and it was a very poor-to-very good quality and potential for gas beds in the Chuditch field. The intensities of gas generation and expulsion were more than of oil ones either in the Sahul Platform or in the Malita Graben. The Plover, Petrel (Frigate) and Echuca Shoals formations source rocks in the wells Chuditch 1 and Heron 1, except for the Flamingo Formation in the well Chuditch 1, had higher gas and oil expelling efficiencies than the Plover Formation source rock of the wells in the Sunset-Loxton Shoals field. The hydrocarbon migrated mainly from the Upper Jurassic Frigate Shale source rock in the Malita Graben depocentre (structurally lower) to the Plover Formation sandstone reservoir in the Sunset-Loxton Shoals field during the Late Cretaceous at 66 Ma. In the Chuditch field, the hydrocarbon migration to the Plover Formation sandstone reservoir was initiated during the Late Miocene at 7.5 Ma from the Middle Jurassic Plover Formation source rock in the well Chuditch 1. Nowadays, the main migration pathways are from the southeastward and southward of the Sunset-Loxton Shoals field, and from southward and eastward of the Chuditch field, precisely from the hydrocarbon source kitchens of the Malita Graben depocentre. The traps in the Sahul Platform have been effective to receive the migrated hydrocarbon.
文摘The Malita Graben is located in the northern Bonaparte Basin, between the Sahul Platform to the northwest and the Petrel Sub-basin and Darwin Shelf to the south. The wells Beluga 1, Heron 1, Evans Shoal 1, Evans Shoal 2 and Seismic Line N11805 are selected to determine the thermal history and potential of hydrocarbon generated from the Plover, Elang, Frigate Shale (Cleia and Flamingo), and Echuca Shoals formations source rocks. The modeling was performed by using Basin Mod 1-D and 2-D techniques. The model results show that the geothermal gradients range from 3.05 to 4.05°C/100 m with an average of 3.75°C/100 m and present day heat flow values from 46.23 to 61.99 mW/m2 with an average of 56.29 mW/m2. The highest geothermal gradient and present-day heat flow values occurred on a terrace north of the Malita Graben. These most likely indicate that hot fluids are currently variably migrating into this structure. The lower geothermal gradient and heat flow values have been modeled in the southeast sites in the well Beluga 1. The northern Bonaparte Basin experienced several deformation phases including lithospheric thinning;hence, heat flow is expected to vary over the geological history of the basin. The higher paleo-heat flow values changing from 83.54 to 112.01 mW/m2 with an average of 101.71 mW/m2 during Jurassic rift event (syn-rift) were sufficient for source rocks maturation and hydrocarbon generation during Cretaceous post-breakup sequence (post-rift) in the study area. The Tuatara (Upper Frigate Shale) Formation source rock with type II & III kerogen dominantly showing mixed oil- and gas-prone, and Plover Formation with type III and gas prone have never reached the peak mature oil window in the well Beluga 1. This area indicates that the maturity of source rocks is low and considered to be from poor-to-good organic richness with poor-to-fair potential for hydrocarbons generation. The post mature Cleia (Lower Frigate Shale) and Echuca Shoals formations source rocks in the well Evans Shoal 1 and an early mature oil window Echuca Shoals formation source rock in the well Evans Shoal 2, characterized by type III kerogen dominantly showing gasprone are a fair-to-very good source richness with poor potential for hydrocarbons generation. The low to high maturity of Echuca Shoals and Petrel (Frigate Shale) formations source rocks in the well Heron 1, Plover Formation source rock in the Evans Shoal 1 well, and Cleia (Lower Frigate Shale) and Plover formations in the well Evans Shoal 2, showing gas-prone with type III and II & III kerogens predominantly, have reached the late mature oil and wet gas generation stages at present day. These last five formations source rocks are seen from poor-to-very good organic richness with poor-to-very good potential for hydrocarbons generation in the Malita Graben.
