FAULT PLANE RESOLUTION USING THE LOW-FOLD 3D SEISMIC TECHNIQUE OVER WOODADA GAS FIELD, PERTH BASIN, WESTERN AUSTRALIA

1987 ◽  
Vol 27 (1) ◽  
pp. 289
Author(s):  
B.J. Evans ◽  
G.A. Paterson ◽  
S.E. Frey
Keyword(s):  
Western Australia ◽  
Seismic Data ◽  
Joint Venture ◽  
Seismic Survey ◽  
Survey Method ◽  
3D Seismic ◽  
Coherent Noise ◽  
Gas Field ◽  
Single Fold ◽  
Processing Techniques

During August 1984, a conventional 2D seismic line and a single fold 3D seismic survey were recorded over the Woodada Gas Field, North Perth Basin, Western Australia. This survey was a joint venture between the Allied Geophysical Laboratories at the University of Houston and the Exploration Seismology Centre's Field Research Laboratory at the Western Australian Institute of Technology. Previous seismic data were so poor that there was confusion about fault orientation and structure in the survey area. In addition, the fault strike direction and extent were unknown at this location. Consequently, 3D seismic acquisition and processing techniques appeared highly applicable to this geological problem.In general, progressive development of seismic data acquisition methods has been towards higher channel, higher multifold 2D and 3D surveys. However, at the Allied Geophysical Laboratories, processing techniques for single-fold 3D data have been developed using model tank data. This processing technique — LO-FOLD 3D — was used to field trial the method, and to test its ability to define faulting between the gas producing well Indoon 1 and dry step-out well Woodada 9. Previous usage of the single-fold 3D survey method was to delineate reefal structures in the Michigan Basin. Beyond this, no published articles discuss the method.With single-fold data, velocity analysis and coherent noise are a problem. Consequently, 2D bin lines through the 3D volume of data were processed in order to improve the signal to noise ratios. The objective was to delineate the fault orientation in the Carynginia Formation, located between 1.3 and 1.5 seconds. Fault delineation was determined from 2D bin lines and time slices, and is interpreted to run diagonally between the two wells.

DEMETER HIGH RESOLUTION 3D SEISMIC SURVEY—REVITALISED DEVELOPMENT AND EXPLORATION ON THE NORTH WEST SHELF, AUSTRALIA

2006 ◽  
Vol 46 (1) ◽  
pp. 101 ◽  
Author(s):  
K.J. Bennett ◽  
M.R. Bussell
Keyword(s):  
High Resolution ◽  
Seismic Data ◽  
New Technologies ◽  
Seismic Survey ◽  
Future Application ◽  
3D Seismic ◽  
Gas Field ◽  
North West ◽  
The North ◽  
Exploration And Development

The newly acquired 3,590 km2 Demeter 3D high resolution seismic survey covers most of the North West Shelf Venture (NWSV) area; a prolific hydrocarbon province with ultimate recoverable reserves of greater than 30 Tcf gas and 1.5 billion bbls of oil and natural gas liquids. The exploration and development of this area has evolved in parallel with the advent of new technologies, maturing into the present phase of revitalised development and exploration based on the Demeter 3D.The NWSV is entering a period of growing gas market demand and infrastructure expansion, combined with a more diverse and mature supply portfolio of offshore fields. A sequence of satellite fields will require optimised development over the next 5–10 years, with a large number of wells to be drilled.The NWSV area is acknowledged to be a complex seismic environment that, until recently, was imaged by a patchwork of eight vintage (1981–98) 3D seismic surveys, each acquired with different parameters. With most of the clearly defined structural highs drilled, exploration success in recent years has been modest. This is due primarily to severe seismic multiple contamination masking the more subtle and deeper exploration prospects. The poor quality and low resolution of vintage seismic data has also impeded reservoir characterisation and sub-surface modelling. These sub-surface uncertainties, together with the large planned expenditure associated with forthcoming development, justified the need for the Demeter leading edge 3D seismic acquisition and processing techniques to underpin field development planning and reserves evaluations.The objective of the Demeter 3D survey was to re-image the NWSV area with a single acquisition and processing sequence to reduce multiple contamination and improve imaging of intra-reservoir architecture. Single source (133 nominal fold), shallow solid streamer acquisition combined with five stages of demultiple and detailed velocity analysis are considered key components of Demeter.The final Demeter volumes were delivered early 2005 and already some benefits of the higher resolution data have been realised, exemplified in the following:Successful drilling of development wells on the Wanaea, Lambert and Hermes oil fields and identification of further opportunities on Wanaea-Cossack and Lambert- Hermes;Dramatic improvements in seismic data quality observed at the giant Perseus gas field helping define seven development well locations;Considerably improved definition of fluvial channel architecture in the south of the Goodwyn gas field allowing for improved well placement and understanding of reservoir distribution;Identification of new exploration prospects and reevaluation of the existing prospect portfolio. Although the Demeter data set has given significant bandwidth needed for this revitalised phase of exploration and development, there remain areas that still suffer from poor seismic imaging, providing challenges for the future application of new technologies.

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.

RECENT DISCOVERIES IN THE PYRENEES MEMBER, EXMOUTH SUB-BASIN: A NEW OIL PLAY FAIRWAY

2005 ◽  
Vol 45 (1) ◽  
pp. 233 ◽  
Author(s):  
J.P. Scibiorski ◽  
M. Micenko ◽  
D. Lockhart
Keyword(s):  
Seismic Data ◽  
Joint Venture ◽  
Depositional Environments ◽  
3D Seismic ◽  
High Quality ◽  
Gas Field ◽  
Geological Information ◽  
Key Factor ◽  
Complex Structural ◽  
3D Seismic Data

Recent drilling by BHP Billiton Pty Ltd in WA-155-P(1) and WA-12-R, on behalf of its partners Apache Energy Ltd and INPEX ALPHA LTD, has resulted in the discovery of four oil fields in the southern Exmouth Sub-basin, namely Ravensworth, Crosby, Stickle and Harrison. These discoveries, together with the earlier discoveries made by West Muiron–5 and Pyrenees–2, define the Early Cretaceous Pyrenees Member play fairway.The Pyrenees Trend play was first conceived in 1999 following appraisal of the Macedon gas field (Keall, 1999), but the concept remained dormant until the integration of geological information with high quality 3D seismic data led to the recognition of hydrocarbon related seismic attributes in the postulated play fairway.Ravensworth–1 intersected a 37 m gross oil column below a 7 m gas cap in high quality Pyrenees Member sandstones beneath the regionally significant Intra- Hauterivian Unconformity. Ravensworth, located on a northeast–southwest trending fault terrace, is a complex structural-stratigraphic trap that relies on separate top, base and cross-fault seals. High quality 3D seismic data coupled with recent interpretation techniques were integral to its discovery. In particular, the quantitative interpretation of seismic amplitude populations was a key factor in decreasing exploration risk.The Ravensworth discovery was followed by successful exploration wells on the adjacent Crosby, Stickle and Harrison fault terraces. Four appraisal wells have since been drilled at the northern ends of the main discoveries.The oil in the Pyrenees Member discoveries is biodegraded, moderately viscous (8–11 cp) and heavy (18–19° API gravity). Methane-dominated gas caps were intersected in Ravensworth–1, West Muiron–5 and Pyrenees–2.The recent drilling and coring campaigns by BHP Billiton and others in the Exmouth Sub-basin have significantly advanced knowledge of the stratigraphy and depositional environments of the late Tithonian to early Berriasian Macedon, Muiron and Pyrenees Members of the lower Barrow Group. The lower Barrow Group is a third order sequence deposited rapidly in marine to fluviodeltaic environments in response to the breakup of Gondwana and the onset of active rifting along the West Australian margin.BHP Billiton and its joint venture partners are assessing the commercial viability of the Pyrenees Trend discoveries.

A REVIEW OF THE RECENT EXPLORATION AND HYDROCARBON POTENTIAL OF THE AMADEUS BASIN, NORTHERN TERRITORY

1984 ◽  
Vol 24 (1) ◽  
pp. 19 ◽  
Author(s):  
R. J. Schroder ◽  
J. D. Gorter
Keyword(s):  
Seismic Data ◽  
Joint Venture ◽  
Oil And Gas ◽  
Northern Territory ◽  
Hydrocarbon Potential ◽  
The West ◽  
Gas Field ◽  
Single Fold ◽  
Oil And Gas Field ◽  
Active Exploration

Since commencing operatorship in the Amadeus Basin in June 1980, the Amadeus Joint Venture has acquired 3000 km of multifold seismic data and reprocessed 2500 km of existing single fold and multifold data. These data, integrated with geological, Landsat, gravity and airphoto information, led to the drilling of eight exploration wells, which resulted in two gas discoveries (in the Dingo 1 and West Walker 1 wells) and numerous additional oil and gas shows in the remaining wells.Interpretation of these multi-discipline data has enabled a number of significant structural trends and styles in the Amadeus Basin to be defined. Individual prospects within some of the major structural trends have now been tested by the drill. This paper describes the nature of these structural trends and illustrates geologically and geophysically typical examples of drilled prospects existing within these trends.The primary exploration targets in the Amadeus Basin are the Ordovician Stairway and Pacoota Sandstones (confirmed by the Mereenie Oil and Gas Field, Palm Valley Gas Field, and the West Walker gas discoveries) and the Precambrian-basal Cambrian Arumbera Sandstone (confirmed by the Dingo gas discovery). Geochemical and maturation data indicate that significant additional oil and gas accumulations can be discovered in these formations.Data from Dingo 1, Mt Winter 1 and Finke 1 have again indicated that significant quantities of both oil and gas have been generated in the Late Proterozoic sediments of the Basin. An active exploration program is continuing and will endeavour to confirm these expectations.

A case history of a cost effective 3D seismic survey over the Perth Basin, Western Australia

1989 ◽  
Vol 20 (2) ◽  
pp. 229
Author(s):  
S.C. Stewart ◽  
B.J. Evans
Keyword(s):  
Western Australia ◽  
Three Dimensional ◽  
Cost Effective ◽  
Cost Comparison ◽  
Seismic Survey ◽  
3D Seismic ◽  
Seismic Surveying ◽  
History Of ◽  
The Cost ◽  
Funded Research Project

As part of an industry funded research project into the application of the technique of LOFOLD3D land seismic surveying, a four fold three dimensional seismic survey was performed in the Perth Basin at Moora, Western Australia in July 1987. The volume covered an area of four kilometres by just under two kilometres, producing a total of 23,000 common midpoint traces. The objective was to collect and process the data in such a manner that a three dimensional structural interpretation would result, which would be the same as that resulting from a conventional three dimensional survey. A cost comparison indicates that a commercial LOFOLD3D survey would reduce the cost of performing a land 3D survey to an estimated 20% of the full fold equivalent, and the technique therefore offers potential for substantial savings if it is adopted on a commercial basis.

PRACTICAL USE OF BOREHOLE SEISMIC IN EXPLORATION

1984 ◽  
Vol 24 (1) ◽  
pp. 429
Author(s):  
F. Sandnes W. L. Nutt ◽  
S. G. Henry
Keyword(s):  
Seismic Data ◽  
Seismic Profile ◽  
Seismic Survey ◽  
Vertical Seismic Profile ◽  
Direct Signal ◽  
Seismic Fault ◽  
Time Calibration ◽  
Vsp Data ◽  
Borehole Seismic ◽  
Processing Techniques

The improvement of acquisition and processing techniques has made it possible to study seismic wavetrains in boreholes.With careful acquisition procedures and quantitative data processing, one can extract useful information on the propagation of seismic events through the earth, on generation of multiples and on the different reflections coming from horizons that may not all be accessible by surface seismic.An extensive borehole seismic survey was conducted in a well in Conoco's contract area 'Block B' in the South China Sea. Shots at 96 levels were recorded, and the resulting Vertical Seismic Profile (VSP) was carefully processed and analyzed together with the Synthetic Seismogram (Geogram*) and the Synthetic Vertical Seismic Profile (Synthetic VSP).In addition to the general interpretation of the VSP data, i.e. time calibration of surface seismic, fault identification, VSP trace inversion and VSP Direct Signal Analysis, the practical inclusion of VSP data in the reprocessing of surface seismic data was studied. Conclusions that can be drawn are that deconvolution of surface seismic data using VSP data must be carefully approached and that VSP can be successfully used to examine phase relationships in seismic data.

THE ELANG OIL DISCOVERY ESTABLISHES NEW OIL PROVINCE IN THE EASTERN TIMOR SEA (TIMOR GAP ZONE OF COOPERATION)

1995 ◽  
Vol 35 (1) ◽  
pp. 44
Author(s):  
I. F. Young ◽  
T.M. Schmedje ◽  
W.F. Muir
Keyword(s):  
Seismic Data ◽  
Late Jurassic ◽  
Joint Venture ◽  
Seismic Survey ◽  
Normal Faults ◽  
Commercial Development ◽  
The North ◽  
3D Data ◽  
Porosity And Permeability ◽  
Timor Sea

The Elang-1 oil discovery in the Timor Gap Zone of Cooperation (ZOC) has established a new oil province in the eastern Timor Sea. The discovery well, completed in February 1994, recorded a flow of 5,800 BOPD (5,013 STBOPD) from marine sandstone of the Late Jurassic Montara beds. The oil is a light (56° API), undersaturated oil with a GOR of approximately 550 SCF/STB. Elang-1 was the first well drilled by the ZOCA 91-12 Joint Venture and only the fifth well in the ZOC since exploration of this frontier area resumed in 1992.The Elang Prospect, initially mapped by Petroz in the late 1970s on the basis of regional seismic data, was detailed by the 1992 Walet Seismic Survey. The prospect is the main crestal culmination on the Elang Trend, a prominent structural high to the north of the Flamingo High that was established during continental break-up in the Late Jurassic. The Elang Trend is bounded to the south by a series of en-echelon normal faults and connecting relay ramps and comprises a number of horst and tilted fault blocks.Elang-1 tested a near crestal culmination on the Elang Prospect and intersected a 76.5 m gross oil column below 3,006.5 m RT. At time of drilling this oil column was the thickest that had been encountered by any well in the Northern Bonaparte Basin. Good quality reservoir sandstone in six discrete bodies were intersected within the Montara beds. Core-measured porosity and permeability range up to 17 per cent and 2.2 Darcies within the oil column.Subsequent to the Elang discovery, the Joint Venture recorded a 402 km2 3D survey over the Elang Trend. Elang-2, an appraisal well spudded in September 1994 prior to receipt of the 3D data, established the lateral continuity of the Montara beds reservoirs. Flow rates of 6,080 BOPD (5,300 STBOPD) and 7,500 BOPD (5,970 STBOPD) from separate intervals have confirmed that high deliverabilities can be expected from individual sandstones. Further appraisal drilling is planned in the first half of 1995. This is expected to lead to commercial development of the field.

Noise suppression in 2D and 3D seismic data with data-driven sifting algorithms

Geophysics ◽  
2019 ◽  
Vol 85 (1) ◽  
pp. V1-V10
Author(s):  
Julián L. Gómez ◽  
Danilo R. Velis ◽  
Juan I. Sabbione
Keyword(s):  
Seismic Data ◽  
Noise Suppression ◽  
Department Of Energy ◽  
Time Slice ◽  
3D Seismic ◽  
Coherent Noise ◽  
Data Set ◽  
Amplitude Data ◽  
3D Volume ◽  
2D And 3D

We have developed an empirical-mode decomposition (EMD) algorithm for effective suppression of random and coherent noise in 2D and 3D seismic amplitude data. Unlike other EMD-based methods for seismic data processing, our approach does not involve the time direction in the computation of the signal envelopes needed for the iterative sifting process. Instead, we apply the sifting algorithm spatially in the inline-crossline plane. At each time slice, we calculate the upper and lower signal envelopes by means of a filter whose length is adapted dynamically at each sifting iteration according to the spatial distribution of the extrema. The denoising of a 3D volume is achieved by removing the most oscillating modes of each time slice from the noisy data. We determine the performance of the algorithm by using three public-domain poststack field data sets: one 2D line of the well-known Alaska 2D data set, available from the US Geological Survey; a subset of the Penobscot 3D volume acquired offshore by the Nova Scotia Department of Energy, Canada; and a subset of the Stratton 3D land data from South Texas, available from the Bureau of Economic Geology at the University of Texas at Austin. The results indicate that random and coherent noise, such as footprint signatures, can be mitigated satisfactorily, enhancing the reflectors with negligible signal leakage in most cases. Our method, called empirical-mode filtering (EMF), yields improved results compared to other 2D and 3D techniques, such as [Formula: see text] EMD filter, [Formula: see text] deconvolution, and [Formula: see text]-[Formula: see text]-[Formula: see text] adaptive prediction filtering. EMF exploits the flexibility of EMD on seismic data and is presented as an efficient and easy-to-apply alternative for denoising seismic data with mild to moderate structural complexity.

Reprocessing legacy three-dimensional seismic data from the Halfmile Lake and Brunswick No. 6 volcanogenic massive sulphide deposits, New Brunswick, Canada

2019 ◽  
Vol 56 (5) ◽  
pp. 569-583 ◽  
Author(s):  
Gilles Bellefleur ◽  
Saeid Cheraghi ◽  
Alireza Malehmir
Keyword(s):  
New Brunswick ◽  
Seismic Data ◽  
Three Dimensional ◽  
Massive Sulphide ◽  
Seismic Survey ◽  
Deep Zone ◽  
3D Seismic ◽  
Massive Sulphide Deposits ◽  
Volcanogenic Massive Sulphide ◽  
Sulphide Deposits

We reprocessed legacy three-dimensional (3D) seismic data from the Halfmile Lake and Brunswick areas, both of which were acquired for mineral exploration in the Bathurst Mining Camp, New Brunswick. Each 3D seismic survey was acquired over known volcanogenic massive sulphide deposits and covered areas with strong mineral potential. Most improvements resulted from a reduction of coherent and random noise on prestack gathers and from an improved velocity model, combined with re-imaging with dip moveout corrections and poststack migration or prestack time migration. At Halfmile Lake, the new imaging results show the Deep zone and a possible extension of the sulphide mineralization at greater depth. True amplitude processing has shown that this anomaly has strong amplitudes and is offset from the Deep zone by a shallowly dipping fault (<15°). With the clearer geological context provided by our results, this anomaly, which appears as a stand-alone anomaly on an original image obtained by Noranda Exploration Ltd., becomes a defendable exploration target. Nonorthogonal acquisition geometry and receiver patches of the Brunswick No. 6 3D seismic survey generated artefacts after dip moveout processing that reduced the overall quality of the seismic volumes. By using a filtering approach based on the application of a weighted Laplacian-Gaussian filter in the Kx–Ky domain, we reduced the noise and improved the continuity of reflections. We also imaged the short and flat reflections observed previously only in the shallow part of prestack time migrated data. These short reflections appear as diffractions on the filtered stacked section with dip moveout corrections, indicating that they originate from small geological bodies or discontinuities in the subsurface.

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