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

Surface-related multiples in Ocean Bottom Cable (OBC) data cannot be removed by directly applying standard SRME, which requires sources and receivers that are surface consistent. The ray paths needed for a complete surface-multiple prediction can be achieved by combining streamer and OBC data. The combination allows fully data driven SRME to be extended to OBC data. However, streamer data is not always available.

In this paper, we demonstrate that the required data to predict surface-related multiples in OBC data can be constructed using inter-source and inter-receiver interferometry, and the multiples can then be predicted similarly as in SRME. The work flow does not require knowing any subsurface information.

We propose and successfully apply on a real 3D seismic dataset from the North-West Australian shelf a new technique that uses well information to correlate anisotropy with velocity for localized lithology driven anomalies. We assume that localized variations in both velocity and anisotropy are caused by changes in the lithology (shale vs carbonate vs sandstone etc). This should result in some correlation between anisotropy anomalies and velocity anomalies. We use well information to establish such a correlation. Our technique produces geology conformal PSDM anisotropic velocity models and reduces depth misties.

Capillary forces control the spatial distribution of pore fluids during two phase flow. Capillarity and fluid distribution are known to influence seismic signatures. By comparing recently developed capillarity-patchy saturation models for different fluid-patch distributions, we obtain an understanding of the underlying connection between capillarity and velocity and attenuation in patchy-saturated reservoir rocks. Our results show that, for the same gas saturation and patch size, P-wave velocity as well as attenuation manifest differently for various fluid distributions. The key parameter in controlling these characteristics is the specific surface area of the fluid patches. This work provides further insights into the relation between the seismic signatures and the two phase flow underpinning saturation information.

Noise in seismic data can create significant challenges for the integration of 4D information into seismic history matching procedures. Impedances derived from a seismic inversion are usually compared to impedances provided by the coupling between a fluid flow and a petro-elastic model. The problem is that uncertainties associated with noise in seismic data are rarely carried though all the seismic inversion steps. And the noise in seismic data can alter the correlation between acoustic impedance and fluid saturation, resulting in erroneous estimates of reservoir properties.

We hypothesize that the amplitude domain could be a better option than the impedance domain for seismic history matching, considering seismic noise. To verify this hypothesis we analyse amplitude and impedance changes as a function of water saturation and seismic noise. We demonstrate that the noise in seismic data causes higher variations on seismic inversion results than on amplitudes. A cross-domain comparison suggests that these impedance variations can be as high as their values derived from the seismic baseline survey.

These results indicate that matching time-lapse seismic and fluid flow data in the amplitude domain may be more reliable than using the impedance domain - in the presence of strong seismic noise. Errors in seismic data, such as noise, need to be considered when undertaking seismic history matching, and proper uncertainty analysis is required for accurate reservoir predictions.

We present a case study from the North West Shelf of Australia where the complexity of the overburden consists of several thin multi-level channel systems filled with a combination of anomalously high or low velocity sediments. Not accounting for these strong velocity variations accurately, can lead to subtle image distortions affecting the underlying section down to and including the reservoir level. This can have significant impact on the volumetric estimates of reserves in place. To resolve these complexities in the overburden, full waveform inversion (FWI) was utilized to generate an updated earth model exploiting both early arrivals and reflection events. One caveat to using full waveform inversion is the need for low frequencies to be present in the seismic data, or, the initial starting velocity model must contain the correct low wavenumber components. However, conventional seismic data acquired at shallow tow depths are usually band limited particularly at the very low frequencies. Our case study will discuss these issues along with other limitations that this “conventional data” presented along with the workflows and quality control methods adapted to this data in order to converge to a plausible, high resolution earth model.

Borehole Seismic has played vital role in aiding the better understandings of the conventional and unconventional reservoirs around the world in the last few decades. In VSP technique we have an advantage of listening and measuring the formation velocities at seismic scale in the vicinity of the formations while on contrary in surface seismic measurements, it is done from surface.

In vertical seismic profile (VSP) technique, the direct arrivals are recorded in addition to the reflections below current sensor depth, which makes it feasible to use the reflections to predict ahead of current depth, detailed methodology will be discussed in the paper.

In this paper, we will discuss a case history where look-ahead VSP have been successfully employed by reducing the pre-drill depth uncertainty of reservoirs from tens of meters to within a meter. Schlumberger’s down-hole seismic tool was used to acquire intermediate look-ahead VSP. The data was acquired in open hole, few hundred meters above the target intervals. Fast-track processing of the field data and timely delivery of a high quality product allowed a rapid interpretation, which resulted in significant savings in relatively high cost offshore environment.

The objective of this work is to assess the effect of noise and parameterisation on the performance of the stochastic time lapse inversion. To do so, a noise-free synthetic dataset created for a feasibility study of an actual CO2 sequestration project (CO2CRC Otway Project) was inverted and used as a baseline. Noise (random and coherent) was added to the seismic data, input parameters changed and the results were compared with the baseline case.

The findings for wrong parameterisation cases were very encouraging and consistent with the theory.

When random noise was added to the input seismic data the algorithm was able to recover the true model within an acceptable margin of error. However, addition of coherent noise affected the inversion result significantly. Only when the root-mean-square (RMS) amplitude level was comparable to the one in the difference volume the algorithm was able to actually differentiate the noise from the signal.

These findings support the idea of a careful processing to avoid coherent noise and a judicious interpretation when it is unavo idable. Finally a new indicator was developed to calculate the improvement in detectability after the input of new data using the stochastic time lapse inversion.

In this paper we present a case study of 4D seismic acquired over the Pyrenees Fields, offshore Western Australia. The Pyrenees trend was discovered with the drilling of the West Muiron-5 discovery well in 1993 which found oil and gas within the Pyrenees member sandstones. Production at Pyrenees started in 2010.

Before the start of production, a dedicated 4D baseline survey was recorded over the fields in 2006. A detailed modelling study concluded that a 4D monitor survey would provide useful information for reservoir surveillance and infill drilling decisions. The monitor survey was acquired in 2013, and the overall quality of the 4D was excellent with high 4D signal strength and low 4D noise.

The 4D response at Pyrenees is broadly consistent with the modelling. The main response is softening of the reservoir caused by gas coming out of solution produced by a pressure drop within the reservoir. The 4D response to changes in oil saturation is small. Incorporating the 4D interpretation into field development is ongoing, and so far it has been useful for refining the stratigraphic model, determining fault seal integrity, and determining the sealing capacity of intra-field faults.

Stratigraphic forward modelling (SFM) is an important subsurface modelling method. A numerical SFM program, such as the Sedsim software used in this study, is able to quantitatively model the sedimentation process with time in order to predict rock properties away from well data.

Although numerical SFM is a powerful technique, it is important to quantify and minimise the uncertainty in the resultant stratigraphic model. This uncertainty can be reduced by producing synthetic seismic traces from the results of the stratigraphic model. This simulated seismic may then be compared to observed seismic over the same area and the parameters of the stratigraphic model modified based on the results of the comparison.

In order to generate synthetic seismic from the results of a stratigraphic model, sediment properties from the stratigraphic model must be converted to acoustic properties. This becomes challenging at inter-well locations, or locations with little or no well control. Fortunately, such conversion can be achieved by the application of a suitable rock physics model even at those challenging locations.

The integration of a Sedsim stratigraphic model and the Velocity-Porosity-Clay (VPC) rock physics model in the Cornea field, Browse Basin, Australia shows the importance of integrating geological and geophysical methods in order to reduce uncertainty when predicting subsurface properties.

Borehole televiewer data is an important source of data on structural and stratigraphic discontinuities in both the mining and petroleum industries. Manually picking features in downhole image logs is a labour-intensive and hence expensive task and as such is a significant bottleneck in data processing. It is also a subjective process.

We present a new algorithm and workflow for automatically detecting and analysing planar structures in downhole acoustic and optical televiewer images. First, an image complexity measure highlights areas most suitable for automated structure detection. Changes in the image complexity can be used to locate geological boundaries. Second, structures are automatically detected, with each structure having an associated confidence level; users can apply a threshold to the confidence values to adjust the quality and quantity of the detected structures based on the image quality and geological complexity. Third, structures that have been detected but that do not meet the structure confidence threshold can be interactively assessed and if necessary selected. We also provide tools for rapidly picking sets of equivalent structures and reducing structures to a set of representative picks.

Quantitative interpretation of time-lapse seismic data is an ongoing challenge. Understanding the velocity-saturation relations and changes caused by CO2 injection play an important role for the application of seismic monitoring techniques to carbon dioxide storage projects.

High uncertainties associated with well log measurements affected by borehole conditions can affect our ability to constrain a rock physics model. Seismic measurements, such as Vertical Seismic Profile (VSP), that span both the near-well region and far beyond the borehole can provide good control for correcting these measurements and reducing the uncertainties thereafter.

In this paper, we analyse the observed time delays in time-lapse VSP data from the Frio CO2 injection test site by employing an integrated approach of rock physics and seismic forward modelling to reduce uncertainties in the choice of the dry frame modulus and velocity-saturation relations. First, we confirmed the quality of pre-injection well logs velocities with VSP data. Afterwards, we use inverse Gassmann relations to calculate the dry frame properties of the reservoir with different input parameters for the grain moduli with fluid substitution applied for uniform saturation of brine and CO2. Finally, forward modelling of the results is implemented to compare the response with field VSP data.

Our investigation shows that VSP data can help constrain the choice of dry frame modulus, and thus the velocity-saturation relation. The rock physics model best matches the VSP results using large grain moduli and uniform saturation for fluid substitution.

We present a new method to generate reservoir models by combining geostatistical simulation and optimization of multiple objective functions; including seismic data matching (i.e. a reservoir model seismic matching loop). Our method is used to estimate static reservoir models by simultaneously integrating several datasets including well logs, geologic information and various seismic attributes. The key advantage of our proposed method is that we can define multiple objective functions for a variety of data types and constraints, and simultaneously minimize the data misfits. Using our optimization method, the resulting models converge towards Pareto fronts, which represent the sets of best compromise model solutions for the defined objectives. We test our new approach on a 3D object-oriented reservoir model, where variogram-based simulation techniques typically fail to produce realistic models. Our results indicate that improved reservoir facies and porosity models and flow-unit connectivity can be obtained with this new multi-objective optimization approach.

In passive-source monitoring, an accurate velocity model is important to precisely estimate microseismic source locations, and to understand changes in reservoir properties. In this study, we employ frequency-domain full waveform inversion in order to obtain a high-resolution velocity model by exploiting full wavefields. We demonstrate the feasibility of the method for a surface geophone array by inverting for time-lapse 4D velocity changes in a realistic subsurface model. Our method successfully estimates the small velocity changes of a few percent within layers of 10s of meters, even for a single passive seismic source event. The analysis of wavepaths and gradients suggests that keys for the successful inversion are the use of full wavefields (both first and scattered arrivals), the vicinity of velocity changes to the source, and the wide-aperture surface array.

For decades, the Taranaki basin has been New Zealand’s only producing basin whilst exploration for large new hydrocarbon discoveries has moved to more frontier basins. Statistically speaking, the Taranaki basin should still hold numerous large fields; however, the information currently available is not sufficient to solve the challenges in understanding the petroleum system. The North Taranaki basin has widespread 2D seismic coverage and numerous wells that have not encountered commercial accumulations. This is attributed to the structural complexity in the basin and the absence of necessary information to help understand the basin evolution. An oilfield services company identified the North Taranaki graben as one area that has huge potential yet to be understood. A modern broadband, long-offset 3D survey was modelled and expected to provide the necessary information to finally understand the petroleum system and provide evidence for material hydrocarbon accumulations. In this investigation we assess the hydrocarbon potential of the basin using the newly acquired data. Advanced acquisition techniques were implemented for increased coverage and bandwith, including continuous line acquisition, sliding-notch broadband acquisition and imaging techniques, and delta source, resulting in a full broadband acquisition. Raypath distortions and depth uncertainty are significantly reduced processing through vertical transverse isotropy (VTI) anisotropic Kirchhoff prestack depth migration with a geologically constrained velocity model. Resolution of the deepest sections in the central graben have identified structures never before seen, as well as fault definition critical to understand charge. Here, we demonstrate the potential of the basin that has been unlocked thanks to the technology advances in acquisition and processing. 3D seismic interpretation and amplitude-versus-offset (AVO) analysis support the renewed potential of the basin.

In this paper, we propose a method to enhance the separation of primaries and multiples by utilizing the ultra-sparseness property of the 3D curvelet transform. By extending our earlier work on the 2D method, our current 3D primary-multiple separation method takes into account the coherence between neighbouring gathers, and extends the Bayesian Probability Maximization (BPM) based separation mechanism into the 3D curvelet domain. The primaries and multiples are differentiated by utilizing the traces of neighbouring gathers in an additional dimension; this further promotes their separation compared to the 2D curvelet domain method. Moreover, this 3D curvelet domain separation method produces robust results regardless of the ordering of data as long as they are organized in a volumetric manner. Additionally, we have also introduced a 3D spatiotemporal constraint for handling the deviation from linearity or planarity of the seismic events. We demonstrate the improvement of the 3D curvelet domain primary-multiple separation method on synthetic and field data examples, by comparing the results with those produced by existing separation methods.

Reservoir characterization objectives are to estimate the petrophysical properties of the prospective hydrocarbon traps and to reduce the uncertainty of the interpretation. In this framework, we present a workflow for petrophysical joint inversion of seismic and EM attributes to estimate the petrophysical model in terms of porosity and water saturation. This study realizes the joint inversion within the probabilistic structure provided by the Bayesian theory. The algorithm is applied to a real hydrocarbon exploration scenario to evaluate its contribution to the interpretation phase. 3D volumes of estimated porosity and saturation, show how the joint inversion of acoustic impedance and electrical resistivity can provide a quantitative description of the reservoir properties and with it a measure of uncertainty, which is consistent with the petrophysical model and observations.

The methods most frequently used to process borehole acoustic data are based on semblance analysis. Two most commonly utilized semblance implementations are: slowness-time coherence and slowness-frequency coherence. Both of them are relatively robust under noisy well conditions. They deliver slowness value across the receiver array, and, as the quality control measures, coherence peak value and frequency dispersion curve.

Semblance processing might be substituted by instantaneous frequency-slowness method based on complex wave form analysis. Instantaneous frequency -slowness delivers rich set of quality control measures. Among them are the velocities, the goodness and standard deviation across the receiver array, and instantaneous frequency and slowness wave forms computed between adjacent receiver pairs. Furthermore, since computations are performed across adjacent receivers, the vertical resolution is limited to the offset between receivers. Thus the effect of multiple semblance peaks observed while the receiver array is passing through the high acoustic impedance contrast is eliminated. Also, the method is capable to detect underperforming receivers. Finally it can help to control mixed acoustic mode conditions.

Instantaneous frequency-slowness method delivers robust results under good to moderately noisy well data. The set of quality measures it delivers is much broader than the one generated by the semblance method.

Vertical Seismic Profiling (VSP) is renowned for its high resolution images of the subsurface. By and large, the images derived are beneath the well. Now a new technique allows imaging above the borehole by utilizing free surface multiples as a secondary source. A number of conditions need to be met for this technique to successfully meet its objectives. This paper presents a case study of data acquired recently in the Carnarvon basin and processed to derive an image above the well. The high-resolution, multiple-free VSP image allows verification of the shallow part of the subsurface. This information can be used to identify drilling hazards, faults and generally improve subsurface interpretation. The result can also be used to overcome the limitations of poor cementing which often causes casing ringing noise, which in itself is detrimental to VSP imaging. Subsequently, the size of the VSP image for this survey was increased by a factor of 2, thus greatly improving the value of acquisition.

Beach Energy has been the sole interest holder and operator of the 7,200 km² Lake Tanganyika South block since 2010. The block is located within the western arm of the East African Rift System. The prospectivity of the lake sequence was enhanced by large oil discoveries in the similar geological environment of Lake Albert in Uganda and in the eastern part of the rift in Kenya. The lack of wells drilled in the lake to date make predicting sedimentary sections difficult. In 2010 Beach Energy commissioned CGG to fly a FALCON^® Airborne Gravity Gradiometer (AGG) and a high-resolution airborne magnetic (HRAM) survey over the Lake Tanganyika South block in order to map the basin structural framework and the depth to magnetic basement. The AGG survey facilitated the imaging of the architecture of the rift zone and the interpreted sediment thickness provided an indication of prospective petroleum target areas. This information was used to plan a subsequent 2D marine seismic survey, which was shot in 2012. The preliminary results from the 2D marine seismic survey has confirmed a rifting structure similar to that encountered further north at Lake Albert in Uganda. A number of targets over tilted fault blocks, low-side rollovers and mounded features, have been identified for follow-up from the seismic sections. Natural oil seeps evident on the surface of Lake Tanganyika, which have been sampled and analyzed by Beach Energy, also indicate that a working petroleum system is present in the sedimentary section of the rift beneath the lake.