Glacial deposits within the Lower Kulshill Group (Late Carboniferous-Early Permian) were initially recognised in cores from onshore wells in the southeastern Bonaparte Basin in the 1960s. Subsequent offshore wells have extended the distribution of the glaciogene units 100 km to the north. Their capacity to entrap oil and gas was proven by the Turtle and Barnett wells, located on the offshore Turtle High. Similar age glaciogene rocks occur within the Cooper Basin of central Australia, where they contain oil and gas reserves, and in the Canning, Carnarvon and Perth basins of Western Australia. Using sparse cores, electric logs, palynology and a sequence stratigraphic interpretation of 2D seismic data, the distribution of potential reservoir sandstones and sealing lithologies of the glaciogenic strata has been mapped for the offshore southeastern Bonaparte Basin. This study highlights the petroleum trapping potential associated with sub-glacial ice tunnel valley features, which are widespread in the offshore part of the basin.
Gas was discovered in intra-Mt Goodwin Sub-group sandstones (Ascalon Formation) of the southeastern Bonaparte Basin in Blacktip–1 in 2001 from a zone characterised by a discrete seismic amplitude anomaly. This integrated study uses wireline logs, cores, cuttings, palynology, micropaleontology and geochemical analyses to determine the depositional environment of the Mt Goodwin Sub-group reservoirs and the source rock potential of this large, latest Permian (Changhsingian) to Early Triassic (Induan Olenekian) section of the Bonaparte Basin in northern Australia. Specific outcomes include a better understanding of the Early Triassic reservoir sandstone depositional environment and recognition of marker horizons on electric logs and seismic profiles, resulting in a more consistent regional interpretive framework for the uppermost Permian (Changhsingian) and Early Triassic (Induan Olenekian), in the Bonaparte Basin.
Rumaila, Iraq, is one of the biggest oil fields in the world, producing through multiple stacked clastic and carbonate reservoirs and relying on several recovery mechanisms such as natural aquifer drive and water flooding which have changed the initial fluid distribution. To evaluate the change of fluids distribution, multi-detector pulsed neutron (MDPN) instruments are run within the field. MDPN measurements require careful interpretation accounting for logging conditions and formation environments to provide an accurate result of multicomponent fluid saturations so well work activity can be optimised, and production and recovery can be maximized. Compatibility with legacy data is also critical for use in time lapse evaluations. Recently, the MDPN technology diversified with more instruments being developed. Field trials are required to understand backwards compatibility for some of the common nuclear attributes as well as benchmarking and calibrating the nuclear models with the in-situ measurements. While all share the same physics principle, the responses can vary owing to instrumentation design, characterization and nuclear attributes extraction in the field. We will present the data integration approach taken by the production team using historical and latest generation MDPN data, some acquired for the first time in the clastic and carbonate formations of Rumaila field. The paper will describe BP’s in-house workflow customised for MDPN derived saturation in Rumaila. This will address the nuclear attribute screening and selection process for the two types of reservoirs (clastic and carbonate) and the associated displacement mechanisms. Data from multiple MDPN instruments are used to illustrate the robustness of our workflow that accounts for borehole configuration, formation properties, reservoir fluids properties and detailed nuclear models for each tool. The nuclear model driven interpretation showed that logging conditions and reservoir properties can significantly impact the accuracy of fluid saturation. The uncertainty in MDPN derived saturation can be reduced if the deviations from notional values are known. Because of similar sand-clay properties, the carbon oxygen response in the clastic reservoir showed a unique pattern challenging the conventional understanding of such data. Additional to reservoir complexity, new challenges will be faced in relation to wellbore access because more wells are completed with electric submersible pumps (ESP). In ESP completed wells, the access to reservoir section will be thru Y-tools using slim MDPN instrumentation. Our study identified the optimal procedures and best nuclear attributes that can be logged in these conditions without increasing the saturation uncertainty.
The Blacktip Gas Field is located offshore in the southern Bonaparte Basin, Australia. The main reservoirs are the Early Permian Keyling and Treachery Formations. The field supplies gas to the Northern Territory utility Power and Water Corporation from two deviated gas production wells via an unmanned well-head platform to shore at Yelcherr near Wadeye in the Northern Territory. The field will deliver gas to the Northern Territory's Power and Water Corporation over a period of 25 years. One of the potential upsides of the gas field is the shallow and previously overlooked Early Triassic Mount Goodwin Sub-Group sandstones and also the Early Permian Torrens and Fossil Head Formations. Eni successfully acquired more data from the drilling of the development wells over these sections, with the objective being to fully assess minor gas shows observed in the original Blacktip-1 discovery well. The Mount Goodwin Sub-Group Sandstones, Torrens Formation and Fossil Head Formation are a thick sequence of inter-bedded shale, siltstone and very fine sandstones. The intervals are thinly bedded, and this makes conventional wireline difficult to interpret. Acquiring a wireline image log and performing a petrophysical thin-bed analysis has helped define the net sandstone thickness and net pay thickness of these formations. Performing geochemical analyses on mud gas samples collected in isotubes has helped to characterise the gas composition throughout the formations. In addition, the identification of moveable gas and verification of the extent of the gas columns has been achieved through the acquisition of formation pressure points and bottom- hole samples by Modular Formation Dynamic Tester (MDT). The conclusion is that from review of recently acquired data the Mount Goodwin Sub-Group Sandstone, Torrens Formation and Fossil Head Formations show good potential for future development in the Blacktip Field. A comparison between conventional log analysis and thin bed analysis is also discussed, with estimates of net sand and net pay thickness contrasted. Blacktip Field is 100% owned and operated by Eni Australia.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
customersupport@researchsolutions.com
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.