The Canterbury Great South Basin in New Zealand: From Plate Tectonics to Migration Modeling – Re-Discovering Hidden Giants?
The Canterbury Great South Basin (CGSB) is located offshore east of the South Island of New Zealand and covers an area of more than 160,000 km2. The CGSB is an extensional basin associated with Cretaceous rifting and break‐up of the Gondwana supercontinent. Prior to extension, the CGSB was located on the active eastern margin of Gondwana where arc‐related terranes were accreted from the late Palaeozoic through Jurassic, as reflected in the complex basement configuration of New Zealand. Subsequent Mid‐Cretaceous extension led to the development of NE‐SW rift basins characterized by en echelon half graben systems that evolved from isolated to connected depocentres as extension progressed. Fourteen wells have been drilled in the basin to date. Eleven wells encountered hydrocarbons and four sub‐commercial discoveries were made. Main exploration efforts occurred in the 1970s and 1980s and only one well within the basin was drilled on 3D seismic. Regional seismic mapping reveals that the CGSB has three dominant structural trends, a NW‐SE trend associated with pre‐rift terrane accretion and SW‐NE and WSW‐ENE trends associated with rift extension. Syn‐ and post‐rift coals and coaly mudstones constitute the main source rocks (SR) within the basin and are known to have sourced giant oil and gas fields within the Late Cretaceous Gippsland (AUS) and Taranaki Basins (NZ). The Gippsland Basin was part of the same rift system as the CGSB and the opening of the Taranaki Basin commenced at the end of the rifting within the CGSB. SR samples from these analogous basins show similar quality as samples from the CGSB. The main reservoirs within the CGSB are net transgressive sands directly overlying pre‐rift highs. Pre‐rift lithologies as well as depositional environments are the main controlling factor on reservoir quality. Late Cretaceous marine transgressive shales act as top seals for theses sands. A large dataset of source rock data was corrected for maturity and used as source rock input for a regional basin model. Source rock extension within the CGSB was based upon GDE maps as well as on seismic facies analysis. Thermal gradients were extrapolated from wells, based upon sedimentary thicknesses as well as pre‐rift composition. Oil and gas expulsion of identified source rock intervals was modelled and fits well with HC shows and discoveries within the basin. Seal capacities of Late Cretaceous marine shales were evaluated via MICP measurements. Due to the high expulsion GORs of these liquid prone coals, seal capacity has a major impact on hydrocarbon phase. A prospect specific high resolution migration model was run and measured seal capacities were integrated into the model. The model captures the interaction between migration vs. fluid phase behavior and trap closure vs. seal capacity and highlights the potential for spill at the deeper levels vs partial leakage at the shallower levels. The latter leads, in multiple scenarios, to retention of a significant oil column in the target trap. This study clearly shows the potential of this underexplored frontier basin and de‐risks a giant drill ready basin centric prospect, which has been identified on 3D seismic, showing direct HC indications. These results could only be achieved by incorporating all available geological data (e.g. seal, reservoir and SR data) and shows the high value of a detailed petroleum system assessment in a frontier basin.
AAPG Datapages/Search and Discovery Article #90349 © 2019 AAPG Hedberg Conference, The Evolution of Petroleum Systems Analysis: Changing of the Guard from Late Mature Experts to Peak Generating Staff, Houston, Texas, March 4-6, 2019