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Abstract Northern Carnarvon Basin is located in North West Shelf of Western Australia. The basin has over 10km sediments and owns both oil-prone and gas-prone sediments and is the current largest oil and gas producing basin in Australia. A geological section through this basin is shown in Figure 1, the complex geological settings from shallow to deep leads to significant processing challenges. In the vintage processing, the seismic image at reservoir level is deteriorated due to the presence of following geological complexities: 1) rugose water bottom, 2) shallow frequent canyons or channel systems, 3) shallow spatial-variant Tertiary carbonates, and 4) shallow gas chimneys and other geo-bodies. These complex overburdens plus limited small-angle coverage of primary reflections from narrow azimuth (NAZ) streamer surveys make it very difficult for ray-based reflection tomography to resolve the shallow velocity. As a result, the target image suffers from large well mis-ties, low signal-to-noise ratio (S/N) and severe event undulations. In addition, shallow fast-velocity layers cause severe illumination issues for deep targets which are compounded by limited offsets of NAZ surveys. Furthermore, localised absorption effects from gas pockets lead to dimming amplitudes for events beneath them. To deal with these issues, we propose to use time-lag full wave-form inversion (TLFWI) to resolve the velocity of complex overburdens and least-squares Q prestack depth migration (LS Q-PSDM) to compensate for illumination issues and absorption effects for the latest reprocessing. In the following sections, application procedure and results of these two technologies will be discussed. Seismic inversion was also conducted to assist the processing and analysis of the final result.
Abstract The North West Shelf of Australia contains a late Paleozoic to Cenozoic sedimentary succession, which attains a thickness of over 10 km and is dominated by Triassic to Lower Cretaceous sediments. The deeper plays exist at multiple stratigraphic levels including oil-prone Jurassic sediments and faulted gas-prone Triassic sediments. The area has been proven difficult as far as seismic imaging is concerned, particularly over the Madeline trend. The presence of a hard, rugose water bottom, strong reflectors beneath the water bottom, and shallow Tertiary carbonates make the Dampier Sub-basin vulnerable to multiple contamination, amplitude distortion, lower signal-to-noise ratio (S/N) and unreliable AVO response. Poor seismic quality in the data has been a significant barrier to reducing exploration risk. In the 1990s, East Dampier (1992, blue polygon in Figure 1) and Keast (1997, yellow polygon in Figure 1) seismic data were acquired in East-West and North-South directions respectively, in an effort to better understand the impact from the shallow complex overburden. To address these challenges, the Demeter survey was acquired in 2003 (black polygon in Figure 1) with a denser acquisition grid. The overall seismic quality was improved, but the results still contained a significant level of residual multiples. Later, the Fortuna survey, the most comprehensive multi-sensor seismic survey on the North West Shelf of Australia to date, was acquired in 2014 with the aim to provide better subsurface imaging (pink polygon in Figure 1) from different acquisition perspectives. The data was processed with advanced processing technology, including shallow water demultiple, deghosting and high definition tilted orthorhombic velocity model building (Birdus et al., 2017). However, the final results were still suffering from a number of challenges, specifically: 1) strong residual multiple in near offsets, 2) low S/N ratio, particularly at reservoir level, and 3) inconsistency from near to far stack resulting in unreliable AVO. In this paper, the Dixon area (green polygon), considered as the most challenging area in the Dampier Sub-basin, was chosen as the testing area for our work. By integrating high-end imaging technology, for example dual-sensor deghosting, multi-survey surface related multiple elimination (MAZ-SRME), and multi-azimuth processing (MAZ stack), we will illustrate how we have overcome many of these imaging challenges.
Santos Energy has received approval from the Northern Territory's Department of Environment and Natural Resources to drill the Tanumbirini 2H and Inacumba 1/1H wells on Exploration Permit 161, clearing the way for the resumption of shale gas exploration in the resource-rich McArthur Basin. The green light comes after a moratorium on hydraulic fracturing in the Northern Territory, levied in 2016, was lifted in 2018. Approval for Santos' environment management plan for its McArthur Basin EP 161 Drilling Program 2019 follows the June environmental consent for civil works at and around the wells and 2D seismic acquisition. Santos said it is wrapping up drilling of the Dukas 1 well in the Amadeus Basin with the Ensign 965 rig and will determine the rig's next location based on its release date. Kevin Gallagher, Santos managing director and chief executive officer, said the company will "be moving as quickly as possible and doing our best to beat the approaching wet season."
The goal is to define and understand the distribution of sands and shales on the basis of seismic reflection data. The modeling and inversion are supported by the good quality of seismic data. This study underpins the benefits of seismically constrained reservoir modeling. The use of probabilistic inversion to map geological features is a new insight in the applicability of this methodology. The study field is located in the Carnarvon Basin offshore western Australia.
We showcase an innovative campaigning and business-focused approach to reservoir monitoring of multiple fields using 4D (time-lapse) seismic. Benefits obtained in terms of cost, speed and the quality of insights gained are discussed, in comparison with a piecemeal approach. Challenges and lessons learned are described, with a view to this approach becoming more widely adopted and allowing 4D monitoring to be extended to smaller or more marginal fields.
An offshore seismic acquisition campaign was planned and successfully executed for a sequence of four 4D monitor surveys for fields located within 250 km of each other on the greater Northwest Shelf of Australia. The four monitors were acquired in H1 2020 comprising (in this order): Pluto Gas Field M2 (second monitor), Brunello Gas Field M1 (first monitor), Laverda Oil Field M1 and Cimatti Oil Field M1.
Cost savings expected from campaigning were realised, despite three cyclones during operations, with success largely attributed to detailed pre-survey planning. Also important were the choice of vessel and planning for operational flexibility. The baseline surveys were diverse and required careful planning to achieve repeatability between vintages over each field, and to optimise the acquisition sequence – minimising time required to reconfigure the streamer spreads between surveys. The Cimatti baseline survey was acquired using a dual-vessel operation; modelling, combined with now-standard steerable streamers, showed a single-vessel monitor survey was feasible. These optimisations provided cost savings incremental to the principal economy of sharing vessel mobilisation costs across the whole campaign.
Both processing and evaluation (ongoing at the time of writing) are essentially separate per field, but follow a consistent approach. Processing is carried out by more than one contractor to debottleneck this phase, with products, including intermediate quality control (QC) volumes, delivered as pre-stack depth migrations. While full evaluation of the monitor surveys to static and dynamic reservoir model updates will continue beyond 2020, key initial reservoir insights are expected to emerge within days of processing completion, with some even earlier from QC volumes. Furthermore, concurrent 4D evaluations are expected to result in fruitful exchanges of ideas and technologies between fields.
The Jurassic Plover Formation is one of two reservoirs in the Ichthys Field, North West Shelf of Australia. It consists of fluvial to shallow-marine sandstones, shales and igneous rocks. The objective of this study is to build multiple scenario-based models to optimise development planning in preparation for the upcoming production phase.
We have integrated data and interpretations of thin sections, cores, well logs and seismic data to create multiple geological concepts for the field and to identify key geological uncertainties. As the reservoir is geologically complex and many uncertainties were initially identified, it is essential to single out those uncertainties which have a significant impact on the development planning. We have established the key uncertainties and optimal model design for practical use through multi-disciplinary discussions and by running sensitivity models to check the production performance.
A rock type (RT) scheme has been devised based on detailed petrographic observations and justified in terms of sedimentology and diagenesis. Using the scheme, a wide range of permeability variations in the sandstones has been captured and modelled. Environments of deposition (EOD) are firstly interpreted at core and well-log scales, then upscaled to the model zone scale. The EOD interpretations are laterally extended using lithology (sandstone, shale and igneous rock) probability maps derived from quantitative seismic interpretation (QSI). Multiple EOD scenarios are generated to capture the possible range of reservoir distributions. Each EOD is characterised by a unique net-sand porosity and RT proportion based on the well data. These values are used to define multiple possible porosity trends and RT proportions, guided by the EOD maps. The distribution and quality of the reservoir sandstones have been identified as key uncertainties. Another key uncertainty is reservoir compartmentalisation, thought to be mainly caused by sheet-like igneous intrusions. Subtle seismic lineaments are regarded as possible indications of such igneous intrusions, and multiple compartmentalisation scenarios have been prepared based on our understanding of igneous activity across the field. Reservoir structure and water saturation are also recognised as key uncertainties. Integrating the key uncertainties, we have established a practical modelling workflow and built multiple scenario-based models to cover a sufficient range of geological uncertainty. The workflow is also adaptive for future history matching, enabling us to flexibly edit the model properties under geological constraints.
A decision tree for development planning, which defines a series of decisions for the well sequence depending on the well results, will be prepared based on the multiple scenario-based models delivered in this study. This will enable us to prepare for any potential decision-making in advance. The development planning will be continuously optimised throughout the production phase by simply selecting the scenario-based models most in line with the well results.
We propose a method to estimate uncertainties for automatic channel detection in 3D seismic volumes using Bayesian convolutional neural network. We measure heteroscedastic aleatoric uncertainty and epistemic uncertainty. Epistemic uncertainty captures uncertainty of the network parameters, while heteroscedastic aleatoric uncertainty accounts for noise in the seismic volumes. We train a network inspired by UNet architecture (Ronneberger et al., 2015), on 3D synthetic seismic volumes, and then apply it to field data. Tests on 3D field data sets from the Browse Basin, offshore Australia, and from Parihaka in New Zealand, prove that uncertainty volumes are related to geologic uncertainty, model’s mispicks, and input noise. Using channel probability and uncertainty volumes, interpreters can accurately identify channel geobodies in 3D seismic volumes and also understand the predictions of model. Presentation Date: Tuesday, October 13, 2020 Session Start Time: 1:50 PM Presentation Time: 1:50 PM Location: 362C Presentation Type: Oral
Analysis of 3D seismic data in Cenozoic strata, located in the offshore North Carnarvon Basin (NCB), Australia, reveals a network of channel like features that migrate the Rankin platform, into the Exmouth plateau. These observed features, identified as submarine gullies, are characterized as being a system of geometrically closely, dense sub-linear channels confined within the upper to lower slope regions. The occurrence and geometries of these submarine features along the shelf to slope area is a function of the morphology of the slope, and the equilibrium between accommodation space, sediment supply, and sea level changes. We focus on applying methods that not only include qualitative analyses but quantifying our observations in order to improve our understanding of the factors that drive the depositional system. We compute and utilize the curvature, variance, and sweetness seismic attributes to enhance our interpretation and characterize the different sedimentary features present within the submarine gullies in the Paleogene sequence of the study area. Presentation Date: Wednesday, October 14, 2020 Session Start Time: 1:50 PM Presentation Time: 3:30 PM Location: Poster Station 10 Presentation Type: Poster
The presence of a hard rugose water bottom, strong near water bottom reflectors, and shallow Tertiary carbonates makes the Dampier sub-basin of Australia’s North West Shelf vulnerable to multiple contamination. The strong multiple energy in the data has been a significant barrier to reducing exploration risk. As such, multiple attenuation is still a key step to improving seismic image quality and thus allowing for enhanced interpretation of stratigraphic trap geometries and gassy charges. We present a case study from a shallow water area of offshore North-West Australia, where we utilize multi-azimuth data jointly to improve the amplitude and phase accuracy of the multiple model prediction, which thus lead to a better subtraction. We will demonstrate that this workflow can overcome the challenges in multiple attenuation and decrease the ambiguity of prospect mapping in underexplored areas. Note: This paperÂ wasÂ acceptedÂ into the Technical Program but was not presented at the 2020 SEG Annual Meeting.
Moore, Jarvis (Black Mountain Exploration) | Hull, Robert (Black Mountain Exploration) | Shelokov, Valeri (Black Mountain Exploration) | Rudge, Tony (Black Mountain Exploration) | Shields, Jessica (Black Mountain Exploration)
The Canning Basin, located on the northern coast of Western Australia, is one of Australia’s largest basins at over 400K sq. km (figure 1), two times the size of the Permian Basin of Texas and New Mexico. It is adjacent to the prolific offshore Carnarvon Basin. A limited number of wells have been drilled with only marginal success on the basin margins bounding the northern deep Fitzroy Trough depocenter. Prograding Devonian and Carboniferous marine carbonates and siliciclastics were deposited in a transitional ramp setting in the Fitzroy Trough; defined source rocks with TOCs of .5 to 4.25% lie within this depocenter but limited information is known about the potential deeper sources. Multiple tectonic phases altered this basin, creating an extensive set of both transpressional and extensional fault systems.
In the Canning Basin, the Australian government estimates potential tight gas resources are 74 TCF, and that an additional 70-150 TCF of shale gas resources are geologically and technically producible. This is approximately equal to the USGS assessed resource size for the entire US Marcellus shale gas system.
Unconventional discoveries like those found in North America have shown that there is significant potential for basin-centered gas around the Fitzroy Trough. Due to Australia’s needs for natural gas, both to feed the declining conventional feedstocks for export, as well as for meeting domestic energy needs, several vertical wells have been stimulated in the last 10 years demonstrating the gas potential within the basin-centered gas play.
Using prior work that was undertaken to develop a geological understanding of the Canning Basin, a US operator has initiated a new evaluation, including a large 3D seismic program (circa ∼200 sq. miles), with a commitment to future testing, drilling and stimulation of unconventional wells to help better define and understand the play with an eye toward economic production.
Using the wealth of prior work that was undertaken to develop an understanding of Canning Basin geology, Black Mountain Exploration has initiated a fresh, robust evaluation of the basin-centered play within a large exploration permit along the northern margin of the Canning Basin within the Fitzroy Trough (Figure 2). This evaluation has included extensive utilization of the existing data within the northern part of the basin and will include a future acquisition of a large 3D seismic program. With this evaluation is a commitment to future testing, drilling and stimulation of unconventional wells to help better define the resource play. A review of the geochemical, petrophysical and vintage 2D seismic data establishes an extensive basin-centered gas fairway beginning at 2000m and continuing to over 4500m in depth. This fairway steps down from the basin margins into the depths of the Fitzroy Trough and is analogous and correlative to a similar petroleum system that hosts significant gas discoveries on the opposite margin of the trough.