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.

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.

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.

CarbonNet progress towards a declaration of identified storage formation at the Pelican site with a new high-resolution 3D seismic dataset

2020 ◽  
Vol 60 (2) ◽  
pp. 718
Author(s):  
Nick Hoffman
Keyword(s):  
High Resolution ◽  
Greenhouse Gas ◽  
Oil And Gas ◽  
Co2 Storage ◽  
Gas Storage ◽  
Frequency Resolution ◽  
Seismic Survey ◽  
3D Seismic ◽  
Long Term Storage ◽  
Gippsland Basin

The CarbonNet project is making the first ever application for a ‘declaration of an identified greenhouse gas storage formation’ (similar to a petroleum location) under the Offshore Petroleum and Greenhouse Gas Storage Act. Unlike a petroleum location, however, there is no ‘discovery’ involved in the application. Instead, a detailed technical assessment is required of the geological suitability for successful long-term storage of CO2. The key challenges to achieving a successful application relate to addressing ‘fundamental suitability determinants’ under the act and regulations. At Pelican (Gippsland Basin), a new high-resolution 3D seismic survey and over 10 nearby petroleum wells (and over 1500 basinal wells) supplement a crestal well drilled in 1967 that proved the seal and reservoir stratigraphy. The GCN18A 3D marine seismic survey has the highest spatial and frequency resolution to date in the Gippsland Basin. The survey was acquired in water depths from 15 to 35 m with a conventional eight-streamer seismic vessel, aided by LiDAR bathymetry. The 12.5 m bin size and pre-stack depth migration with multiple tomographic velocity iterations have produced an unprecedented high-quality image of the Latrobe Group reservoirs and sealing units. The 3D seismic data provides excellent structural definition of the Pelican Anticline, and the overlying Golden Beach-1A gas pool is excellent. Depositional detail of reservoir-seal pairs within the Latrobe Group has been resolved, allowing a confident assessment of petroleum gas in place and CO2 storage opportunities. The CarbonNet project is progressing with a low-risk storage concept at intra-formational level, as proven by trapped pools at nearby oil and gas fields. Laterally extensive intra-formational shales provide seals across the entire structure, providing pressure and fluid separation between the overlying shallow hydrocarbon gas pool and the deeper CO2 storage opportunity. CarbonNet is assessing this storage opportunity and progressing towards a ‘declaration of an identified greenhouse gas storage formation’.

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.

scholarly journals Linear Noise Removal Using Tau-P Transformation on 3D Seismic Data of Al-Samawah Area - South West of Iraq

2019 ◽  
pp. 2664-2671
Author(s):  
Ahmed Hussein Ali ◽  
Ali M. Al-Rahim
Keyword(s):  
Seismic Data ◽  
Signal To Noise Ratio ◽  
Noise Removal ◽  
Noise Attenuation ◽  
3D Seismic ◽  
South West ◽  
3D Data ◽  
P Transformation ◽  
3D Seismic Data ◽  
Different Sources

Tau-P linear noise attenuation filter (TPLNA) was applied on the 3D seismic data of Al-Samawah area south west of Iraq with the aim of attenuating linear noise. TPLNA transforms the data from time domain to tau-p domain in order to increase signal to noise ratio. Applying TPLNA produced very good results considering the 3D data that usually have a large amount of linear noise from different sources and in different azimuths and directions. This processing is very important in later interpretation due to the fact that the signal was covered by different kinds of noise in which the linear noise take a large part.

THE APPLICATION OF 3D SEISMIC INTERPRETATION TECHNIQUES FOR OPTIMISING WELL PLACEMENT: FORTESCUE FIELD RE DEVELOPMENT, GIPPSLAND BASIN

1997 ◽  
Vol 37 (1) ◽  
pp. 31
Author(s):  
P.J. Ryan ◽  
T.E. Vinson
Keyword(s):  
High Precision ◽  
Seismic Data ◽  
Development Program ◽  
Seismic Interpretation ◽  
3D Seismic ◽  
Well Placement ◽  
Seismic Waveform ◽  
Attribute Analysis ◽  
Definition Of ◽  
Gippsland Basin

In order to achieve successful drilling results on mature fields, geophysical analysis has become increasingly focussed on the application of high precision 3D seismic interpretation and analysis techniques. These techniques were critical to the success of the re-development program recently completed on the Fortescue Field* Gippsland Basin. Fortescue, initially developed in 1983, contains an estimated oil reserve of 300 million barrels. The field is currently over 80 percent depleted. To offset declining production and develop remaining reserves, an 18 well additional drilling program together with upgrades to platform topsides and production facilities was conducted on the field from October 1994 to October 1996.Many of the proposed additional drilling opportunities relied on oil being trapped structurally updip from existing completions. Given the size (approx. 1 MSTB) and subtle, low relief nature of the targets being pursued, the precision of conventional 3D seismic interpretation techniques was inadequate to optimise the location of wells. This necessitated the development of a series of specific tools that could provide high resolution definition of both the trap and lithology as well as optimising well placement.These high precision interpretation techniques include: reservoir subcrop edge prediction through qualitative calibration of geological models to seismic data: the assessment of overburden velocity distortions of the seismic time field by utilising isochron mapping and interval attribute analysis; and prediction of trap geometries and lateral stratigraphic variations by the application of seismic waveform attributes.The application of these advanced 3D seismic interpretation techniques and their integration with related geoscience and engineering technologies resulted in the completion of a successful 18 well re-development program for the Fortescue field.

Innovative high trace density design with broadband seismic data acquisition in the Cooper–Eromanga Basins, Australia

2018 ◽  
Vol 58 (2) ◽  
pp. 773
Author(s):  
John Archer ◽  
Milos Delic ◽  
Frank Nicholson
Keyword(s):  
Seismic Data ◽  
Survey Design ◽  
New Technology ◽  
Time Frame ◽  
Seismic Survey ◽  
Baseline Survey ◽  
3D Seismic ◽  
Seismic Data Acquisition ◽  
Trace Density ◽  
Cooper Basin

Through a combination of innovative survey design, new technology and the introduction of novel operational techniques, the trace density of a 3D seismic survey in the Cooper Basin was increased from a baseline of 140 000 to 1 600 000 traces km–2, the bandwidth of the data was extended from four to six octaves, and the dataset was acquired in substantially the same time-frame and for the same cost as the baseline survey.

Long Beach 3D Seismic Survey: Data Mining Continuous Passive Seismic Data

2013 ◽  
Author(s):  
D. Hollis ◽  
C. Cox ◽  
R. Clayton ◽  
F. Lin ◽  
D. Li ◽  
...  
Keyword(s):  
Data Mining ◽  
Survey Data ◽  
Seismic Data ◽  
Seismic Survey ◽  
3D Seismic ◽  
Long Beach ◽  
Passive Seismic

Deep learning for multitrace sparse-spike deconvolution

Geophysics ◽  
2021 ◽  
pp. 1-64
Author(s):  
Xintao Chai ◽  
Genyang Tang ◽  
Kai Lin ◽  
Zhe Yan ◽  
Hanming Gu ◽  
...  
Keyword(s):  
Deep Learning ◽  
Seismic Data ◽  
Resolution Enhancement ◽  
Parameter Tuning ◽  
Seismic Exploration ◽  
3D Seismic ◽  
Spatial Continuity ◽  
Additional Information ◽  
3D Data ◽  
3D Seismic Data

Sparse-spike deconvolution (SSD) is an important method for seismic resolution enhancement. With the wavelet given, many trace-by-trace SSD methods have been proposed for extracting an estimate of the reflection-coefficient series from stacked traces. The main drawbacks of the trace-by-trace methods are that they neither use the information from the adjacent seismograms and nor take full advantage of the inherent spatial continuity of the seismic data. Although several multitrace methods have been consequently proposed, these methods generally rely on different assumptions and theories and require different parameter settings for different data applications. Therefore, the traditional methods demand intensive human-computer interaction. This requirement undoubtedly does not fit the current dominant trend of intelligent seismic exploration. Therefore, we have developed a deep learning (DL)-based multitrace SSD approach. The approach transforms the input 2D/3D seismic data into the corresponding SSD result by training end-to-end encoder-decoder-style 2D/3D convolutional neural networks (CNNs). Our key motivations are that DL is effective for mining complicated relations from data, the 2D/3D CNNs can take multitrace information into account naturally, the additional information contributes to the SSD result with better spatial continuity, and parameter tuning is not necessary for CNN predictions. We report the significance of the learning rate for the training process's convergence. Benchmarking tests on the field 2D/3D seismic data confirm that the approach yields accurate high-resolution results that are mostly in agreement with the well logs; the DL-based multitrace SSD results generated by the 2D/3D CNNs are better than the trace-by-trace SSD results; and the 3D CNN outperforms the 2D CNN for 3D data application.

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