- Home
- A-Z Publications
- First Break
- Previous Issues
- Volume 34, Issue 9, 2016
First Break - Volume 34, Issue 9, 2016
Volume 34, Issue 9, 2016
-
-
Constraining a 3D anisotropic tomography inversion with 800 wells – A Canadian oil sands case history
Authors Sylvestre Charles, Jiwu Lin, Lijuan Du and Ahmed Mouaki Benani ChebihatThis Canadian oil-sands case history is a very shallow play with a complex geology that includes Quaternary thrusting at surface, sinkholes, and highly karsted Devonian carbonates at the base of the notoriously complex McMurray reservoir. Despite this challenging environment, we were able to demonstrate that Depth Imaging brought significant improvements as compared to the routinely used time imaging. Recent developments in Anisotropic Pre-Stack Depth Imaging technologies provided a better focused and better positioned 3D subsurface image that accurately tied several hundreds of wells. These results were achieved using steering filters, solver bounds and simultaneous multi-parameter tomography inversion while constraining the tomography updates with the well top picks from over 800 wells. Surveys of different vintages, geometries, orientations and shooting directions were regularized using 5D interpolation and merged together. Besides a better imaging of the subsurface, one of main objective of the project was the characterization of the McMurray reservoir. To that aim, the Anisotropic Pre-Stack Depth Migration (APSDM) generated better conditioned Offset Vector Tile gathers for subsequent pre-stack inversion work. The Alberta oil sands are one of the largest bituminous hydrocarbon reserves in the world (Alberta Energy Regulator, 2015). At reservoir temperature, the bitumen is so viscous that it can almost be considered as a solid. In situ thermal recovery processes such as steam-assisted gravity drainage (SAGD) that lower viscosity and increase mobility are required to extract the bitumen from the reservoir. SAGD operations consist of horizontal well pairs that are drilled into the base of the reservoir. In each pair, one well is drilled about 5 m directly above the other well. The top well is injected with steam to melt the bitumen. The bitumen seeps down towards the bottom producing well, which pumps the bitumen to the surface. The well pairs are generally configured to about ten parallel horizontal well pairs that are around 100 m apart horizontally and are 1000 m long, which constitute a 1-km2 pad.
-
-
-
Reducing the gap between seismic imaging and geology: Horizon consistent velocity analysis and modelling for pre-stack time and depth migrations
Authors Paolo Esestime, Chris Benson, Milos Cvetkovic and Sarah SpoorsS eismic velocities and migration techniques have great impact in the reservoir imaging at any stage of the exploration for hydrocarbons. The effectiveness of a migration algorithm is commonly measured by the ability to boost the signal continuity, against noise and other disturbances such as diffractions from out-of-plane events (Jones, 2010). By contrast, migration is a process applied to reposition the energy from where it originated, to resolve the geometry and positioning of the events. The success of the process is heavily reliant on the velocity field used. The consistency between the velocity field and events is a quality indicator in seismic inversion exercises, for both the low frequency background and the high frequency intervals identified in velocity logs. The migration itself can be seen as an inversion procedure, with the velocity gradients required to be consistent with vertical trends and amplitude events (Guillaume et al., 2011; Benson et al., 2015). The understanding of geological velocities progresses with exploration and the increasing number of wells and geophysical data available, which gradually establish lithological and rock physics properties, together with tectonic and burial history. Several pre-stack algorithms are available for time migration (PSTM) as well as for depth migration (PSDM), which allow the velocity analysis and modelling sequence to more closely integrate geophysical and geological data. Nowadays, pre-conditioned migration velocities are common in the depth imaging, during the processing of PSDM. The approach is applied for complex geology and relies on seismic and non-seismic data, also combined through different joint inversion techniques (Droujinine et al., 2008; Foss et al., 2008; Houghton et al., 2014). We present a migration workflow, originally designed for regional 2D seismic and applicable to 3D, which links the velocity modelling for PSTM with PSDM, and allows geological constraints to be applied at the PSTM stage (Figure 1).
-
-
-
Drilling closer to salt
Authors Ahmed Ammar, Ross Saunders, Chuck Henry, Tim Wilkinson, Mike Frismanis, Mike Bradshaw, Jeff Codd and David KesslerDrilling up-dip wells, in close proximity to salt bodies is common practice in exploration for oil and gas. Imaging of sand layers close to salt however is difficult in many cases owing to the complex geometrical shape of the salt body as well as the rapid change in material properties between the sedimentary section and the salt body. In many cases this results in either drilling into the salt body by mistake, or too low in the target formations. This difficulty is very well known in the Gulf of Mexico shelf which has been a prolific oil and gas producing region for more than 70 years. Over the years, seismic data used for interpretation and prospect generation in this area has been sub-optimal in many cases. Many of the producing fields in the Gulf of Mexico shelf consist of steeply dipping hydrocarbon-bearing sands truncated against salt domes. Unfortunately, in many cases the salt bodies defining the reservoir edges are not well imaged on associated seismic data, making the accurate mapping of the producing reservoir very difficult (Foley et. al., 1991). One solution to the seismic imaging problem can be achieved by design and acquisition of new seismic data. In the past few years, more effort has taken place to acquire new data on the Gulf of Mexico shelf, but dense spacing of surface platforms makes acquiring new surface streamer data difficult. The newer data is mainly acquired using ocean bottom node technology which results in wide azimuth seismic data. The new data has the potential to have much better seismic resolution than the older narrow azimuth streamer data used by the industry for many years. In addition, nodes can be placed much closer to surface installations creating better illumination in these areas. However, because of the complexity of the geology in close proximity to salt bodies, the clear imaging of sedimentary layers near salt remains challenging even when the newest seismic data is used.
-
-
-
Dual-sensor data and enhanced depth imaging sheds new light onto the mature Viking Graben area
The Viking Graben area in the Central North Sea was the initial focus of a series of early 3D GeoStreamer dual-sensor surveys between 2009 and 2012 (Figure 1). These MultiClient surveys immediately demonstrated significant image quality improvements achieved with the dual-sensor towed streamer seismic in an area characterized by significant subsurface complexity. After more than 50 years of active exploration, the Viking Graben is widely regarded as a mature basin whose petroleum system is thought to be well understood. Many of the classic hydrocarbon targets of the region, including the large rotated Jurassic fault blocks of Gullfaks and Oseberg, and the Paleocene and Eocene fan systems of the Heimdal and Frigg fields, have already been exploited. Challenges remain to stratigraphic interpretation and mapping of sands within the Upper Jurassic and it is therefore important to have data which has sufficient penetration and accurate positioning of reflectors to continue to explore these levels. Determining the exploration opportunities beyond these classic targets also requires optimization of the seismic data. The Eocene sands have been extensively mapped, but the Paleocene fans are less well known. Although the play is proven, the more subtle sands of the Ty and Maureen formations have been masked by artefacts caused by shallow events. In addition, several of the classic plays have now become the subject of re-evaluation. Better resolution and deeper signal penetration with dual-sensor data has provided detailed insight into many of these plays and also improved the understanding of the overall connectivity of several highly compartmentalized reservoirs that are often comprised of a variety of barriers and baffles. In order to improve the understanding of the geology within this established area and to be able to exploit the fields to their full potential, modern seismic data need to be consistently re-evaluated and subjected to new processing techniques. The remobilized and injected reservoir sands of the Volund field were considered unique at the time of its discovery in 1994, however, many other recent discoveries are also now considered to be the result of remobilized sands. Potentially, known fields such as Balder, with its steep sided reservoir, may also be re-categorized as an injectite rather than a deep marine fan reservoir. Utilizing a depth migrated seismic dataset with reduced artefacts from shallow anomalies may validate this and enable additional fields to be discovered.
-
-
-
Challenges and strategies of interbed multiple attenuation in the Asia-Pacific region
Authors Min Wang, Barry Hung, Xiang Li and Stephane FintzHigh-quality imaging is key to reservoir characterization. Any events, such as interbed multiples, which are not specifically handled by migration algorithms, generate interfering events and distort the wavelets of true reflectors, thus reducing the quality of the final image. For instance, the presence of interbed multiples has a strong impact on the interpretation of fractured basements in Vietnam (Tan et al., 2010). These interbed multiples are generated between strong reflection horizons within the Oligocene and the top of the basement. In Cooper Basin, Australia, interbed multiples generated among the coal beds lower the high-frequency content and a time delay was observed in seismic characterization (Qi, 2013). This distorted imaging is a serious problem for seismic exploration and development. Interbed multiples are a common challenge in the Asia-Pacific region. Many multiple generators, such as the seafloor, carbonate layers, coal seams or volcanic flows, are found in this region, which generate visible interbed multiples. The impact of interbed multiples on inversion and interpretation has been quantified by analysing amplitude-versus-offset (AVO) responses (Iverson, 2014). The results showed that, when isolating subtle variations in rock properties, coherent noise can negatively impact the inversion results, creating a bias in the interpretation. It can be concluded that interbed multiples should either be removed before imaging, or must be correctly addressed in imaging algorithms.
-
-
-
Identification of sweet spots in shale reservoir formations
Authors Ritesh Kumar Sharma and Satinder ChopraThe main goal for shale resource characterization is usually the identification of sweet spots which represent the most favourable drilling targets. Such sweet spots can be picked up as those pockets in the target formation that exhibit high total organic carbon (TOC) content as well as high brittleness. At any well location, when the resistivity and sonic transit-time curves are scaled and overlaid, they follow each other almost everywhere, except in the kerogen-rich zones, where they cross over. While such a cross over is only seen visually, it can be transformed into an attribute known as ΔlogR that incorporates both the resistivity and velocity information and is expected to be high for organic-rich zones. Such a transformation would allow us to identify organic-rich zones only at well locations. In this study, we introduce a methodology for computing ΔlogR as a volume from seismic data. For doing this, the ΔlogR curve computed at well locations is correlated with different attribute curves that can be derived from seismic data. An attribute curve which shows the maximum correlation is selected and crossplotted against ΔlogR to determine the relationship between the two. This relationship is then used for extracting the ΔlogR volume from 3D seismic data.
-
-
-
Seismic volume visualization at your fingertips
More LessVolume visualization has become an essential tool for geoscientists in the oil and gas industry. Using this technology, geosci¬entists interact with volumes of seismic data to locate, isolate, and understand the spatial relationships of important geologic features in a context-rich 3D environment. In the past decade, the continued evolution in hardware and software of mobile devices is putting desktop capabilities in everyone’s palms. As such, mobile devices are becoming more useful as an interactive 3D visualization platform. In this paper, I evaluate and demonstrate the effectiveness of mobile devices to perform seismic vol¬ume visualization. Sub-volumes of data containing different stratigraphic depositional environments were first extracted from three 3D seismic surveys. The rendered 3D graphics were examined in detail. The results illustrate that volume visualization on mobile devices enables the exploration of detailed variations in the seismic response. Therefore, it facilitates the interpretation of the imaged geologic features. I anticipate that mobile devices will revolutionize the interpretation of seismic data volumes by allowing geoscientists to visually examine their data anywhere and at any time.
-
Volumes & issues
-
Volume 42 (2024)
-
Volume 41 (2023)
-
Volume 40 (2022)
-
Volume 39 (2021)
-
Volume 38 (2020)
-
Volume 37 (2019)
-
Volume 36 (2018)
-
Volume 35 (2017)
-
Volume 34 (2016)
-
Volume 33 (2015)
-
Volume 32 (2014)
-
Volume 31 (2013)
-
Volume 30 (2012)
-
Volume 29 (2011)
-
Volume 28 (2010)
-
Volume 27 (2009)
-
Volume 26 (2008)
-
Volume 25 (2007)
-
Volume 24 (2006)
-
Volume 23 (2005)
-
Volume 22 (2004)
-
Volume 21 (2003)
-
Volume 20 (2002)
-
Volume 19 (2001)
-
Volume 18 (2000)
-
Volume 17 (1999)
-
Volume 16 (1998)
-
Volume 15 (1997)
-
Volume 14 (1996)
-
Volume 13 (1995)
-
Volume 12 (1994)
-
Volume 11 (1993)
-
Volume 10 (1992)
-
Volume 9 (1991)
-
Volume 8 (1990)
-
Volume 7 (1989)
-
Volume 6 (1988)
-
Volume 5 (1987)
-
Volume 4 (1986)
-
Volume 3 (1985)
-
Volume 2 (1984)
-
Volume 1 (1983)