The Deep Velocity Structure Beneath the Gippsland Basin from Long-Offset Seismic Data

1992 ◽  
Vol 23 (1-2) ◽  
pp. 69-74 ◽  
Author(s):  
C. D. N. Collins ◽  
J. P. Cull ◽  
J. B. Colwell ◽  
. Willcox
Keyword(s):  
Seismic Data ◽  
Velocity Structure ◽  
Long Offset ◽  
Gippsland Basin

scholarly journals Crustal thickness and velocity structure across the Moroccan Atlas from long offset wide-angle reflection seismic data: The SIMA experiment

2014 ◽  
Vol 15 (5) ◽  
pp. 1698-1717 ◽  
Author(s):  
P. Ayarza ◽  
R. Carbonell ◽  
A. Teixell ◽  
I. Palomeras ◽  
D. Martí ◽  
...  
Keyword(s):  
Seismic Data ◽  
Velocity Structure ◽  
Crustal Thickness ◽  
Wide Angle ◽  
Reflection Seismic ◽  
Long Offset

Application of the migration velocity analysis to a long-offset seismic data in the Ulleung basin, offshore Korea

2020 ◽  
Author(s):  
Woohyun Son ◽  
Byoung-Yeop Kim
Keyword(s):  
Seismic Data ◽  
Velocity Structure ◽  
Velocity Model ◽  
Ulleung Basin ◽  
Velocity Analysis ◽  
Time Processing ◽  
Depth Processing ◽  
Migration Velocity Analysis ◽  
Long Offset ◽  
Marine Seismic

<p>In order to obtain subsurface velocity for field seismic data, a time processing based on semblance velocity analysis has been performed so far. However, since the results of the time processing do not provide velocity information in the depth domain, it is difficult to know the exact subsurface velocity. In this study, to generate accurate velocity, the depth processing using the migration velocity analysis (MVA), which generates more reasonable subsurface velocity structure than the result from the time processing, is applied to the field marine seismic data obtained from Ulleung basin (offshore Korea). A marine seismic source is generated by air-gun (2,289 cu. in.). The long-offset (5.7 km) multichannel seismic (MCS) data were recorded by 456 receivers. The source and receiver spacings are 25 m and 12.5 m, respectively. The seismic survey line is about 168 L-km. The MVA workflow is composed of building a starting velocity model, sorting data to common offset gathers, Kirchhoff prestack depth migration (PSDM), sorting to common reflection point (CRP) gathers, picking residual moveout (RMO), and updating the velocity model. We repeatedly applied the MVA workflow until the remarkable events in the CRP gather were flat. From the results, we could confirm that the depth processing using MVA is successfully applied to field dataset and generates reasonable velocity structure in depth.</p>

Early basin insights and AVO supported leads from new long offset 2D seismic data, Labrador Sea, Canada

2013 ◽  
Author(s):  
Richard Wright ◽  
James Carter ◽  
Deric Cameron ◽  
Tom Neugebauer ◽  
Jerry Witney ◽  
...  
Keyword(s):  
Seismic Data ◽  
Labrador Sea ◽  
Long Offset

P-Wave VTI Anisotropy Measurements from Long Offset Seismic Data

2000 ◽  
Author(s):  
K. Hawkins ◽  
R. Leggott ◽  
G. Williams
Keyword(s):  
Seismic Data ◽  
P Wave ◽  
Long Offset

GOLDEN BEACH: A BRIGHT SPOT

1978 ◽  
Vol 18 (1) ◽  
pp. 109
Author(s):  
R. B. Mariow
Keyword(s):  
Seismic Data ◽  
High Amplitude ◽  
Late Eocene ◽  
Polarity Reversal ◽  
Bright Spot ◽  
Areal Extent ◽  
Water Contact ◽  
Bright Spots ◽  
Gippsland Basin ◽  
Seismic Reflector

The Golden Beach closed anticlinal structure lies five kilometres offshore in the Gippsland Basin. Golden Beach 1A was drilled in 1967 near the crest of the structure and intersected a gas column of 19 m (63 feet) at the top of the Latrobe Group (Late Eocene) where most of the hydrocarbon accumulations in the Gippsland Basin have been found. The gas-water contact lies at a depth of 652 m (2139 feet) below sea level.On seismic data recorded over the structure, a high amplitude flat-lying event was interpreted as a bright 'flat spot' at the gas-water contact. Reprocessing of the seismic data enhanced the bright spot effect and enabled the areal extent of the gas zone to be mapped. The presence of the gas also leads to a polarity reversal of the top of the Latrobe Group seismic reflector over the gas accumulation.Seismic data from other structures containing hydrocarbons in the Gippsland Basin support the concept that bright spots and flat spots are more likely to be associated with gas than with oil accumulations, and that the observed bright spot effect decreases with increasing depth.

THE FORTESCUE FIELD - NEW OIL IN THE GIPPSLAND BASIN

1980 ◽  
Vol 20 (1) ◽  
pp. 130
Author(s):  
R.C.N. Thornton ◽  
B.J. Burns ◽  
A.K. Khurana ◽  
A.J. Rigg
Keyword(s):  
Seismic Data ◽  
Sufficient Information ◽  
Well Log ◽  
Geochemical Analysis ◽  
Water Contact ◽  
Pricing Policy ◽  
Stratigraphic Analysis ◽  
Oil Water ◽  
Oil Pricing ◽  
Gippsland Basin

The Fortescue-1 well drilled in the Gippsland Basin in June 1978 was a dry hole. However, results of detailed stratigraphic analysis together with seismic data provided sufficient information to predict the possible occurrence of a stratigraphic trap on the flank of the giant Halibut structure.Three months later the West Halibut-1 well encountered oil in the Latrobe Group 16 m below that depth carried as the original oil-water contact for the Halibut field. Following wireline testing in both the water and oil-bearing sandstone units, two separate pressure systems were recognised in the well. Three additional wells, Fortescue-2, 3 and 4, were drilled to define further the limits of the field, the complex stratigraphy and the hydrocarbon contacts.Integration of detailed well log correlations, stratigraphic interpretations and seismic data indicated that the Fortescue reservoirs were a discrete set of units stratigraphically younger and separated from those of Halibut and Cobia Fields. Analysis of pressures confirmed the presence of two separate pressure systems, proving none of the Fortescue reservoirs were being produced from the Halibut platform. Geochemical analysis of oils from both accumulations supported the above results, with indications that no mixing of oils had occurred.Because the Fortescue Field is interpreted as a hydrocarbon accumulation which is completely separated from both Halibut and Cobia Fields, and was not discovered prior to September 17, 1975, it qualified as "new oil" under the Federal Government's existing crude oil pricing policy. In late 1979, the Federal Government notified Esso/BHP that oil produced from the Fortescue Field would be classified as “new oil”.

THE YELLOWTAIL OIL DISCOVERY

1983 ◽  
Vol 23 (1) ◽  
pp. 170
Author(s):  
A. R. Limbert ◽  
P. N. Glenton ◽  
J. Volaric
Keyword(s):  
Oil Recovery ◽  
Seismic Data ◽  
Joint Venture ◽  
Seismic Survey ◽  
3D Seismic ◽  
Well Control ◽  
Reservoir Volume ◽  
3D Data ◽  
Small Feature ◽  
Gippsland Basin

The Esso/Hematite Yellowtall oil discovery is located about 80 km offshore in the Gippsland Basin. It is a small accumulation situated between the Mackerel and Kingfish oilfields. The oil is contained in Paleocene Latrobe Group sandstones, and sealed by the calcareous shales and siltstones of the Oligocene to Miocene Lakes Entrance Formation. Structural movement and erosion have combined to produce a low relief closure on the unconformity surface at the top of the Latrobe Group.The discovery well, Yellowtail-1, was the culmination of an exploration programme initiated during the early 1970's. The early work involved the recording and interpretation of conventional seismic data and resulted in the drilling of Opah- 1 in 1977. Opah-1 failed to intersect reservoir- quality sediments within the interpreted limits of closure although oil indications were encountered in a non-net interval immediately below the top of the Latrobe Group. In 1980 the South Mackerel 3D seismic survey was recorded. The interpretation of these 3D data in conjunction with the existing well control resulted in the drilling of Yellowtail-1 and subsequently led to the drilling of Yellowtail-2.In spite of the intensive exploration to which this small feature has been subjected, the potential for its development remains uncertain. Technical factors which affect the viability of a Yellowtail development are:The low relief of the closure makes the reservoir volume highly sensitive to depth conversion of the seismic data.The complicated velocity field makes precise depth conversion difficult.The thin oil column reduces oil recovery efficiency.The detailed pattern of erosion at the top of the Latrobe Group may be beyond the resolution capability of 3D seismic data.The 3D seismic data may not be capable of defining the distribution of the non-net intervals within the trap.The large anticlinal closures and topographic highs in the Gippsland Basin have been drilled, and the prospects that remain are generally small or high risk. Such exploration demands higher technology in the exploration stage and more wells to define the discoveries, and has no guarantee of success. The Yellowtail discovery is an illustration of one such prospect that the Esso/Hematite joint venture is evaluating.

Sign in / Sign up

Export Citation Format

Share Document