ASEG Extended Abstracts - 24th International Geophysical Conference and Exhibition – Geophysics and Geology Together for Discovery, 2015

This study attempts to gain a better insight into the controls on an under-saturated gas discovery, offshore Mozambique, using Geological Expression techniques such as High Definition Frequency Decomposition (HDFD) and multi-attribute classifications with synthetic wedge modelling being used to better understand the results. HDFD highlights known hydrocarbon bearing sands as high magnitudes and shows that structural processes are dominant in controlling their distribution. Observations from the Chaos divided by Envelope attribute lead to gas chimney interpretations and show that faults may be acting as migration pathways for hydrocarbons into and out of the reservoir. The Interactive Facies Classification tool confirms preconceived ideas of a later stage inversion, shows potential deposition fairways and sand-sand juxtaposition across faults confirming that faults are not acting as baffles to fluid flow. Finally synthetic wedge modelling of the reservoir provides an explanation for similar colour responses of the HDFD RGB blend above and below the gas-water contact. We observe that, even though thickness is a dominant controlling factor on the colours in the RGB blend, pore fill plays a role and allows a single stratigraphic layer to be divided based on it. These techniques aided in better understanding and risking the reservoir.

Broadband seismic processing has been proven in marine seismic data obtained with new acquisition techniques. However, we are challenged with what can be achieved towards improving the bandwidth of many legacy seismic data in our library, of which the acquisition configuration and parameters were lacking of information for proper broadband processing requirements, such as accurate receiver depths.

This paper demonstrates some of the broadband processing techniques we applied on legacy 3D and 2D data to bring out the bandwidth and improve the quality of the signal of legacy seismic data.

A total of 109 cuttings were recovered during the IODP expedition 338 in site C0002F down to 2005 mbsf. A special dielectric end-load probe was designed and used for the first time at sea on this sample collection to measure dielectric and electrical conductivity from 10 kHz to 6 GHz. The whole dataset was compared to specific surface area (SSA), mineralogy from XRD measurements and resistivity log while drilling acquired during the expedition to understand the relationship between fluid, clays and lithologies. The dielectric results revealed to be very powerful to: (i) understand the clay composition and content; (ii) re-calibrate cutting depths; (iii) detect unit boundaries and (iv) detect conductive and not-conductive fault systems

Reservoir compartmentalization has a huge bearing on fluid flow within hydrocarbon reservoirs, and can impact overall recovery during field development. Small and sub-seismic faults can have a dramatic effect on the compartmentalization within a reservoir, but until recently they have not typically been incorporated into fault interpretations. This can be due to data fidelity and the amount of time needed to manually pick them. Their omission from the interpretation - and ultimately reservoir models - means the understanding of reservoir compartmentalization is incomplete, hence solving this problem is critical to improve production. Approaches that automatically identify and extract faults from seismic volumes are available. These automated methods aim to emphasize discontinuities within seismic volumes and are usually focused on poststack data. However, they need preconditioned inputs that are often based around a coherence algorithm. This preconditioning aims to suppress noise but can inflict data degradation, which may diminish smaller features in the seismic volumes. This article proposes an enhanced approach using a new combination of preconditioning steps designed to avoid these degradation problems. It also proposes the use of prestack seismic data, which has not traditionally been used for this purpose. Analysis of various pre-stack elements is displayed to show it can delineate more features than poststack data alone in certain noisy areas, such as gas effects or low frequencies. Finally, it demonstrates that the best approach combines results from pre- and poststack analysis to produce a more complete picture of reservoir compartmentalization.

AVO studies have typically been used in the search for gas on the North-West Shelf for decades, but its use for identifying oil filled reservoirs has been limited by the effective meaningful angle range obtainable from the seismic data. We have performed tomographic updates of the anisotropic parameter epsilon to obtain flatter and cleaner gathers out to a much higher angle range than traditional anisotropic assumptions. This then gives the ability to use the data for AVO much more effectively.

Scientific ocean drilling uses several drill ships to work on global scientific problems. These include changes over various time scales in climate, biology and oceanography, extreme life forms beneath the sea bed, planetary dynamics and geological hazards. The International Ocean Discovery Program (IODP) involves 27 countries, including Australia and New Zealand, and is the world’s largest scientific geoscience program. One IODP drill ship, JOIDES Resolution, is working in our general region at present and for several years to come. Although the primary aim of the work is purely scientific, deep stratigraphic wells are always of interest to the petroleum exploration industry. This talk will cover IODP in general, ocean drilling in our region, and the capabilities of the JOIDES Resolution.

Seismic wave form classification techniques have been used to significantly improve the efficiency of the interpretation of the Barrolka field 3D seismic survey. Pattern recognition of seismic shape based on a neutral network has proven to be powerful approach in reducing risk associated with characterising and predicting the extent of the Barrolka field’s historically elusive PC30 reservoir. This technique resulted in recent drilling success with development wells intersecting predicted reservoir and resulting in exceptional initial gas rates, a contrast to the field complex’s 30 years low drilling success. This study has rejuvenated interest to convert the field’s large contingent resource to reserves.

Rock-physics templates (RPT), in combination with seismic AVO inversion data, can be used to screen for hydrocarbon prospects during exploration. With the improved quality and increased use of elastic seismic inversion, there has recently been a paradigm change in prospect mapping in the oil industry, and quantitative interpretation has become a widely used jargon. Rock-physics models are essential in that they help in converting elastic parameters from inversion data to reservoir parameters. Rock physics models plays an important role in many of the stages of seismic AVO inversions; including the petrophysical log evaluations, well ties and wavelet estimation, the setting of parameter constraints during the inversion, and the interpretation of the inversion results in terms of reservoir properties. Rock-physics models can also be used to quality check and modify the low-frequency model used in seismic AVO inversion, and to assess the quality and uncertainties of inverted elastic parameters. In this presentation we will demonstrate the use of rock-physics models during the different stages of seismic inversion, and how these can improve our ability to reveal hydrocarbon-associated anomalies.

We present a case study offshore Malaysia, shallow gas features in the overburden distort the seismic imaging at the target level. While a multifaceted approach involving a combination of seismic acquisition and processing strategies were used to improve the bandwidth of the seismic data, particularly for the low-frequency content of the seismic image, several distortions still existed at the target level. The prominent structural sag evident at the reservoir level is a typical indication that the overlying shallow gas velocity model needed to be resolved and incorporated into a depth migration algorithm.

To resolve the transversally and laterally variant velocity features in the shallow gas areas, a solution that consisted of full waveform inversion (FWI) and high-resolution reflection traveltime tomography was utilized to produce an accurate compressional velocity model. To further resolve the amplitude and phase distortions at the reservoir level due to shallow gas effects, Q tomography was incorporated into the model building phase to derive a space-variant 1/Qmodel and Q compensation was integrated within depth migration.

The integrated approach of broadband receiver acquisition, data processing strategies and high-end Earth model building has cumulatively improved the imaging of the reservoir below the shallow gas anomalies.

We developed a workflow that allows integrating legacy 2D seismic surveys with modern log and core data, validating their consistency, classifying them into rock classes with consistent properties, propagating material properties across each of these rock classes, and using this information to improve reservoir characterization and the assessment of their hydrocarbon resource potential. As proof of concept, we analyzed two intersecting 2D seismic lines shot in 2001 in a frontier basin in Canada to determine the distribution of reservoir quality. Each of these had been separately prestack inverted, but have modern core and log data (as well as legacy log data) which were integrated with the inverted attributes.

Results identify a most prospective class for reservoir quality within the zone of interest, and show that it increases in thickness to the south in the seismic section.

Will development of unconventional reservoirs (tight gas, shale gas and CSG) in Australian proceed as in North America? What aspects of Australian development are more favorable? And what aspects will make development in Australia more difficult or expensive?

Australia currently has a more challenging cost structure than North America, but there are some distinct hidden advantages in Australia’s oil and gas permitting laws. Australia’s gas market appears to be much more attractive, at least for the short to mid-term. And the environmental issues are playing out in Australia in a very similar manner to North America.

Inside Australian companies developing unconventional resources, there is a debate over competing development philosophies that is largely hidden from public view; this is the debate between a low cost factory-like pattern drilling program versus an expensive upfront investment in geoscience data that will hopefully lead to a more economic drilling and completion solution.

Within the subsurface technical realm, a common mantra in North America now is “every shale gas play is different” - meaning that a technical solution for shale gas development in one basin may not work in another basin. With this view, shale gas development in Australia will not be any more or less challenging than trying to adapt Barnett shale gas solutions to the Eagle Ford shale (which is highly successful) or to the largely disappointing Woodford Shale. But there is one significant development challenge common to Australian basins that has not been experienced in North American: higher tectonic stress and higher differential stress. These higher stresses can lead to horizontal fracture stimulation treatments instead of the expected and more favorable vertical frac treatments.

While it is still too soon to pick the successful and unsuccessful unconventional plays in Australia, this talk will attempt to highlight the critical drivers in that success.

Cooper basin Toolachee and Patchawarra sands are difficult to map due to strong seismic reflections from Permian coals. Seismic amplitudes are mainly driven by coal thickness instead of lithology (sand vs shale). We proposed a method for obtaining better sand prediction. This method uses AVO intercept (I) and gradient (G) and the Extended Elastic Impedance (EEI) to highlight the subtle differences between coal-shale and coal-sand interfaces. We test this method by creating several wedge models to understand the effect of coal thickness and lithology on seismic amplitudes. Results are compared with a more traditional method that recognizes a ‘channel’ pattern on stacked seismic and uses a geologic facies model to locate sand with respect to that channel. For the 3D survey used here, our EEI-AVO method ‘finds’ sand in locations predicted by the traditional facies model method as well as in new locations.

Successful identification of volcanic rocks is critical in reservoirs where they have been previously intersected. This is because they impact on reserve estimates and influence fluid flow behaviour. Various studies using seismic inversion data were performed to try to characterise volcanic rocks in a sandstone reservoir in the Plover Formation. We noted that traditional techniques such as cross-plots between P-Impedance (Ip) and Vp/Vs was not very effective in this reservoir due to significant facies overlap at seismic resolution and inversion data quality. Therefore volcanic rock identification was attempted using advanced seismic attribute analysis. This involved testing and evaluating other elastic attributes, either individually or in combinations, to try and segregate volcanic rocks from other lithofacies. Two approaches were adopted to find out a suitable single attribute to identify the volcanic rock: (i) scaling of elastic logs with a non-elastic trend; (ii) generating a single attribute using Ip, Is and LMR cross-plots. Log and seismic scale analysis proved the suitability of both methods in volcanic rock identification. Subsequently, Extended Elastic Impedance (EEI) was applied to generate the EEI equivalent of those single attribute yielding positive results.

Next generation airborne gravity systems are expected to deliver significant improvements in measurement precision and resolution. In rough terrain a major component of the measured data will be the effects of the terrain beneath the aircraft, and corrections are routinely applied to remove most of these terrain effects. In order to fully utilise the higher precision data, advances in estimating these terrain effects will be necessary. This paper will describe some of the steps necessary to improve estimation of terrain effects and demonstrate the expected improvement in target recognition.

Improved mining technology and scarcity of near-surface deposits is forcing the mining industry to explore deeper in the search for economic mineralisation. Reflection seismic is one of the few geophysical methods that have sufficient resolution at depth to constrain geological information of an ore deposit at the drilling scale. Reflection seismic methods can be used to reduce drilling costs by focusing the drilling in strategically important areas. Recently introduced seismic volumetric interpretation techniques have advantages over conventional interpretation techniques where the interpretation is done by slicing the volume in 2D planes. Volumetric interpretation is performed in 3D, in real time, by applying various opacity and transparency filters to the seismic volume from different angles, which enables in-depth understanding of the volume. This initial stage of volumetric interpretation is followed by mapping the interfaces and associated structures of exploration interest.

A 3D high-resolution seismic dataset was collected to investigate steeply dipping to sub-vertical structures in Kevitsa, northern Finland. Automatic fault extraction using a modified ant-tracking workflow was done on the seismic volume.

Volcanogenic massive sulphide (VMS) deposits of Pyhasalmi, Vihanti and Outokumpu in Finland belong to the same mineralized belt but are different in terms of age and detailed deformation history. Results of sonic and density logging show that in these mining camps rock formations hosting the known ore deposits are reflective which encourages the use of seismic reflection method for mapping the subsurface geological structures. A network of seismic reflection profiles was acquired in each study site and these data are utilized in the geological 3D-modeling and deep mineral exploration.

Full 3D inversion of AEM data is not generally available to minerals explorers because of limitations in current algorithms and computer resources. Consequently we must resort to approximations to full 3D AEM inversion to support today’s exploration projects. One form of approximation is to reduce the dimensionality of the inverse problem from 3D to 1D and while layered earth inversion has proven fast and effective in practice, it has limitations in 3D environments. To address these limitations we propose a physically motivated approximate 3D AEM inversion: Quasi3D inversion. Full 3D EM inversion requires calculation of the 3D induced current in the earth whereas the Quasi3D approximation is based on a full 3D inversion but with a simplified, approximate, induced current flow in the earth. We demonstrate the Quasi3D approximation by comparing its response over the interface of a quarter-space model with the full AEM response, and then demonstrate Quasi3D inversion on a challenging synthetic model and on field data. From our work we conclude that the Quasi3D approximation is an effective and efficient approximation which should aid in the interpretation of AEM data for today’s exploration projects.

Several lines of VTEM data flown at different system elevations across a known sulphide body and surface cover with elevated superparamagnetic (SPM) properties were analysed with MAXWELL, layered-earth inversions, LEROIAIR and LEROI. The SPM material was modelled with frequency-dependent magnetic susceptibilities at shallow depth.

Due to their slow late-time decay, SPM responses can be confused with responses of deep conductors and vice versa. Depending on the parameter weighting used, 1D inversions model all late-time responses as deep conductive material or as surficial SPM material. However, the joint 1D inversion of data acquired at different system elevations manages to recover a deep conductor from the sulphide anomaly and elevated SPM values at the location of the SPM response. For the modelled parameters, the VTEM data sets from two elevations (at 70 and 80 m) require a vertical separation of about 10 m to allow for the discrimination between the SPM and sulphide responses. For lower system elevations, less sensor separation is necessary due to the strong gradient of the SPM response.

We suggest that two vertically separated receivers could be used to measure the AEM gradient and depending on the flying height of the transmitter, the vertical offset of the receivers should be between 2 and 40 m.

Conventional voxel-based inversion algorithms can encounter difficulties when inverting airborne time-domain electromagnetic data in three dimensions. In certain environments with these codes, it can be challenging to delineate sharp boundaries between geologic units with large conductivity contrasts and to accurately image thin conductive targets. Furthermore, spurious circular inversion artifacts, known as ringing, can occur around conductive targets.

To address these issues we have developed a parametric inversion code that can be used to find the optimal location, shape and conductivity value of a single anomaly in a homogeneous or heterogeneous background. The algorithm incorporates a Gauss-Newton optimization scheme in conjunction with a level set formulation to outline the anomaly of interest, and can be combined with a conventional voxel-based algorithm in more complicated geologic settings.

The code is shown to be successful with a synthetic data set over a thin dipping plate, and two field data sets. For the synthetic scenario, the parametric inversion recovers the true dip and size of a conductive target with no a priori information. The algorithm also accurately defines the extent of a diamondiferous kimberlite pipe and a dipping massive sulphide deposit beneath a conductive overburden.