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- Volume 35, Issue 12, 2017
First Break - Volume 35, Issue 12, 2017
Volume 35, Issue 12, 2017
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Applications of least-squares pre-stack depth migration in complex geology around the world
Authors Shouting Huang, Zhao Wang, Ming Wang, Adel Khalil, Ping Wang, Xiaodong Wu, Yi Xie, Francesco Perrone and Chu-Ong TingPre-stack depth migration has been an industrial imaging standard for decades, starting from the adoption of Kirchhoff migration in the early Nineties to the emergence of reverse-time migration (RTM) in the late 2000s. These algorithms map the recorded seismic reflection energy from a surface location to a subsurface location, through either a ray-based travel-time table or a waveequation-based propagation engine. In principle, by combining high-fidelity migration algorithms and accurate subsurface velocity models, we can achieve the ultimate goals of seismic imaging: the correct positioning and focusing of the seismic reflectivity of the subsurface geological structures. In reality, however, there are several challenges and issues that need to be addressed before we are able to achieve such an objective, not to mention the fact that most of the time we do not record all subsurface reflections sufficiently owing to limited coverage and sampling of the seismic recording spread. We can consider recorded seismic data to be the result of forward modelling experiments through subsurface structures. To image the reflectivity of the subsurface, we need to reverse the forward wave-propagation effects with an inverse of the forward modelling operator. Essentially, this is an inversion process. However, conventional imaging algorithms are formulated as adjoint operators rather than as true inverses (Claerbout, 1992). This approximation caused image degradation due to irregular and aliased acquisition sampling, limited receiver coverage, noise, and inhomogeneous or poor illumination caused by complex overburden. As a result, standard pre-stack depth migration algorithms suffer from migration artifacts with uncancelled swings, limited bandwidth, and distorted amplitude on subsurface reflectors (Gray, 1997). This is true even for stateof-the-art imaging technology such as RTM (Baysal et al., 1983; Zhang and Zhang, 2009).
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Applying full-azimuth depth imaging in the local angle domain to delineate hard-to-recover hydrocarbon reserves
Authors Alexander Inozemtsev, Zvi Koren and Alexander GalkinHard-to-recover hydrocarbon reservoirs lie at great depths, in complex geological conditions. They are characterized by complex structures, low fluid permeability and a low oil and gas recovery ratio. In Russia today, about 60% of the potential oil and gas fields are located in this type of reservoir. These include hydrocarbon deposits in the Paleozoic basement (pre-Jurassic basement) of Western Siberia, subsalt carbonate sediments under salt dome tectonics, and carbonate and terrigenous deposits in the Volga region and Eastern Siberia. The exploration of these reservoirs benefits from a new, full-azimuth angle domain approach to seismic processing and imaging. This new technology can provide a more detailed depth image of the entire structural-tectonic reservoir skeleton, and a more accurate forecast of the main rock properties of the reservoirs. Conventional seismic depth imaging tools, such as ray-based or beam-based Kirchhoff migrations, applied to rich azimuth seismic data, normally generate multi-azimuth offset-domain common image gathers (CIGs). These are further used for anisotropic velocity model determination and for the characterization of reservoir properties, such as fracture systems. In these types of migrations, the input data is first binned into specific surface offset/ azimuth geometrical groups, such as offset vector tiles (OVT), azimuthal sectors or planner spirals, depending on the acquisition pattern. Each set of binned data is then independently migrated, with the final CIGs being simply a collection of individual images. However, in many cases, particularly when studying hydrocarbon reservoirs below complex geological areas and along steep inclined layers, the offset/azimuth CIGs do not provide the required information (in terms of accuracy and resolution, for example) to achieve the above mentioned goals. Unlike subsurface imaged events along the angle domain CIGs, which indicate ‘true’ local reflectivities, the reflection image events along the offset domain CIGs can be only considered a rough approximation of the ‘true’ reflectivities. Obviously, the accuracy and reliability of the offset domain CIGs are strongly compromised when imaging below complex geological areas with complex wave phenomena. One of the main drawbacks of offset domain imaging, especially in complex geological areas, is its inability to deal with the actual multi-pathing waves which are naturally handled within angle domain imaging.
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Integration of SMTI topology with dynamic parameter analysis to characterize fracture connectivity related to flow and production along wellbores in the STACK play
Authors Adam M. Baig, Ellie P. Ardakani, Ted Urbancic, Dan Kahn, Jamie Rich, David Langton and Ken SilverA number of years ago, there was an appeal to microseismic service providers and end users to go ‘beyond the dots’ in terms of the types of analysis that can be performed to relate the microseismic waveforms to problems in terms of drilling, completion, and field development. While this call to arms has often been interpreted rather specifically, in terms of moment tensor inversion, this is just one aspect of how microseismic data can be looked at beyond the rather limited information afforded to by their locations. Even in terms of determining the moment tensors of microseismic events, the question of how to use this information to affect business decisions is not intuitively obvious. In this paper, we describe a number of analyses that aim to make use of microseismic data, from moment tensors to other source parameters, in the context of a completion in the STACK play in Kingfisher County, Oklahoma. Key to extracting information from these data is the concept that a single microseismic event does not afford a lot of information in of itself. The critical idea is that it is the interaction of different microseismic events which captures processes that are not elucidated in the consideration of events individually. Using the example of seismic moment tensor inversion (SMTI) data, we describe an approach for obtaining a picture of a connected fracture network that can further be described in terms of the percolation properties of the network. This allows for the moment tensor data to be linked to where the hydraulic stimulation fractures connect to the treatment well and therefore the volumes where we may expect production. Further consideration of microseismic event clusters can identify the different deformation processes that accompany the microseismicity. By clustering events of similar character, and considering both how they are distributed in time and space, as well as the insights into their failure processes from a detailed study of their source mechanics, the deformation in the reservoir can be mapped. Characterizing the deformation by the degree of co-seismic (anelastic) deformation allows the processes in the reservoir to be described in terms of different deformation indexes, ‘dynamic parameters’: plasticity index (PI) corresponding to anelastic deformation; stress index (SI) as related to the localized stress behaviour/conditions leading to seismicity; and diffusion index (DI) which describes the rate of stress transfer as it results in seismicity throughout the volume of interest. We introduce the site and give an overview to the microseimsic data acquisition for a lateral well completion in the STACK play (Sooner Trend Anadarko basin Canadian and Kingfisher counties). We then describe an approach for processing these data, through moment tensor inversion, into a picture of the Discrete Fracture Network (DFN). This requires a methodology to group events occurring under like stress conditions to invert for the stress ratio and the principal stress axes, such that the fracture planes may be deterministically derived from the moment tensor data. We also discuss the methodology to determine the cluster-based dynamic parameters. We then illustrate how we can use these tools to arrive at an integrated interpretation of processes occurring during the hydraulic completion, and how these data can be used to affect design decisions for completion and field development.
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Sierra de Reyes 3D seismic survey (onshore Argentina): depth imaging complex geology by applying multi-focusing, Kirchhoff, Beam and RTM workflows
Authors Pablo Borghi, David Curia, Martín Alayón, Paul Veeken, Ignacio Lescano and Daniel JustoSeismic acquisition and processing for imaging the subsurface is an important workflow in the petroleum industry. Complex geological settings such as tectonic thrust belts are a major challenge. The Sierra de Reyes 3D (SR3D) seismic survey in western Argentina is an example of where rough terrain land acquisition is combined with complex structural geology. These two problems have to be solved concurrently during the depth imaging steps. The SR3D land seismic project (270 km2) is located in the SE part of the Ranquil Norte concession (Neuquen Basin, Figure 1). The area lies in the Southern Central Andes, in the external Malargüe fold and thrust belt (FTB). The FTB is characterized by the coexistence of thick and thin skin thrusting. This compressive regime has produced the structural traps of several main oil and gas fields of the northern Neuquen Basin. The further exploration of this hydrocarbon play has driven the development of the SR3D project (Figure 2).
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3D shallow water seismic survey planning to deliver sub-salt imaging in South Gabon
Authors Paolo Esestime, Laura Arti, Milos Cvetkovic, Karyna Rodriguez and Neil HodgsonThe shallow offshore in south Gabon has been explored for more than 50 years, highlighting the potential for oil discoveries.However, exploration of the sub-salt syn-rift section requires an advanced support that only modern, regionally consistent 3D seismic data can provide. Such support was the objective of a large-scale multi-client 3D seismic programme, representing a collaboration between Spectrum Geo Ltd and the Gabonese Hydrocarbon Authorities (Direction Generale des Hydrocarbures (DHG)), which commenced in December 2016. This survey acquired 11,500 km2 of 3D seismic data in the ‘Gryphon Area’ – the shallow offshore of Mayumba and Sette Cama, west of the Olowi Field, in a range of water depths from 20 to 1000 m (Figure 1). Advanced and accurate modelling allowed for the survey specifications to be tailored to the geological setting and the exploration targets. The previous geological and geophysical exploration was taken as background information to develop the new subsurface imaging. For many years the accepted exploration target in South Gabon has been the high-quality transgressive Gamba Sand-stone of Lower Aptian age, located just below the Ezanga Salt Fm. As the base of the salt is separated from the near ubiquitous Gamba Sandstone Fm. by thin shale (Vembo shale member) the main challenge for seismic acquisition therefore has been the accurate imaging of the base salt, and more importantly the accurate depth imaging of this unit. The overburden is complicated by heterogeneous and highly variable velocities in the post-salt carbonate of Madiela Fm., complex geometries of top salt and variable compositions and velocities within the salt. In south-west Congo (Brazzaville), a number of discoveries have been made over the past 4-5 years, in a new intra syn-rift play. This play targets the Djeno Fm., equivalent in age to the lower syn-rift Kissenda Fm. of South Gabon. This play has rarely been targeted in Gabon owing to the poor imaging of the pre-salt section on legacy 2D and 3D data. This article describes the methodology applied to the pre-acquisition study, which guided the acquisition operation and gave a preliminary insight of the challenges to be faced during the processing.
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Global gravity field from recent satellites (DTU15) — Arctic improvements
Authors O.B. Andersen, P. Knudsen, S. Kenyon, J.K. Factor and S. HolmesGlobal marine gravity field modelling using satellite altimetry is currently undergoing huge improvement with the completion of the Jason-1 end-of-life geodetic mission, but particularly with the continuing Cryosat-2 mission. These new satellites provide three times as many geodetic mission altimetric sea surface height observations as ever before. The impact of these new geodetic mission data is a dramatic improvement of particularly the shorter wavelength of the gravity field (10-20 km) which is now being mapped at significantly higher accuracy. The quality of the altimetric gravity field is in many places surpassing the quality of gravity fields derived using non-commercial marine gravity observations. Cryosat-2 provides for the first time altimetry throughout the Arctic Ocean up to 88°N. Here, the huge improvement in marine gravity mapping is shown through comparison with high quality airborne data flown north of Greenland in 2009. An improvement of nearly 50% in terms of standard deviation with the airborne data was found when comparing with older gravity fields such as DTU10 and EGM08, which are the only global marine gravity fields available in the Arctic Ocean north of 80°N.
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Volumes & issues
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Volume 42 (2024)
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Volume 41 (2023)
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Volume 40 (2022)
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Volume 39 (2021)
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Volume 38 (2020)
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Volume 37 (2019)
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Volume 36 (2018)
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Volume 35 (2017)
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Volume 34 (2016)
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Volume 33 (2015)
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Volume 32 (2014)
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Volume 31 (2013)
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Volume 30 (2012)
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Volume 29 (2011)
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Volume 28 (2010)
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Volume 27 (2009)
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Volume 26 (2008)
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Volume 25 (2007)
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Volume 24 (2006)
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Volume 23 (2005)
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Volume 22 (2004)
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Volume 21 (2003)
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Volume 20 (2002)
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Volume 19 (2001)
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Volume 18 (2000)
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Volume 17 (1999)
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Volume 16 (1998)
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Volume 15 (1997)
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Volume 14 (1996)
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Volume 13 (1995)
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Volume 12 (1994)
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Volume 11 (1993)
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Volume 10 (1992)
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Volume 9 (1991)
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Volume 8 (1990)
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Volume 7 (1989)
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Volume 6 (1988)
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Volume 5 (1987)
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Volume 4 (1986)
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Volume 3 (1985)
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Volume 2 (1984)
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Volume 1 (1983)