A NEW TECTONO-STRATIGRAPHIC SYNTHESIS OF THE NORTH WEST CAPE AREA

1991 ◽  
Vol 31 (1) ◽  
pp. 154 ◽  
Author(s):  
R.J. Malcolm ◽  
M.C. Pott ◽  
E. Delfos
Keyword(s):  
Seismic Data ◽  
Joint Venture ◽  
Lateral Displacement ◽  
Landsat Imagery ◽  
Block Rotation ◽  
Surface Mapping ◽  
North West ◽  
The North ◽  
Oil Flow ◽  
Transfer Faults

The North West Cape area in the Exmouth Sub-basin was the site of the first onshore oil flow in Australia at Rough Range-1 in 1953. Subsequently, exploration focused on two large surface anticlines, Cape Range and Rough Range. By 1984, 30 unsuccessful wells had made it clear that the subsurface was far more complex than indicated by the surface mapping and limited seismic data. A detailed reappraisal of the subsurface structure and stratigraphy was needed.A joint venture group operated by Ampol Exploration began a new phase of exploration by recording over 1200 km of seismic data, both regional and detailed, between 1985 and 1989. An integrated interpretation of seismic data, well information and Landsat imagery has improved the understanding of structural and stratigraphic complexities and has given direction to the current exploration effort.Five of the most significant tectonic episodes to affect the North West Cape area have been recognised. They are Late Carboniferous and Early Jurassic (Sinemurian) rifting phases, Callovian-Oxfordian and Berriasian-Valanginian syn-rift pulses related to break-up and, finally, structural inversion in the Late Miocene. Each of these episodes is associated with characteristic structural styles and stratigraphic sequences.Significant lateral displacement along transfer faults during Sinemurian rifting and again during the Berriasian- Valanginian syn-rift pulse has resulted in the formation of tear faults that swing westward and merge with the plane of the transfer faults. Fault-block rotation and uplift associated with these tear faults provide potential structural and stratigraphic traps. The influence that transfer faults have on the hydrocarbon prospectivity of the North West Cape area has been recognised, including their role in the distribution of reservoir and source rocks.These tectono-stratigraphic concepts have provided a sound framework for future exploration in the North West Cape area, and may have implications for hydrocarbon prospectivity in other parts of the North West Shelf and on passive margins elsewhere.

CARNARVON BASIN ARCHITECTURE AND STRUCTURE DEFINED BY THE INTEGRATION OF MINERAL AND PETROLEUM EXPLORATION TOOLS AND TECHNIQUES

2002 ◽  
Vol 42 (1) ◽  
pp. 287 ◽  
Author(s):  
L.L. Pryer ◽  
K.K. Romine ◽  
T.S. Loutit ◽  
R.G. Barnes
Keyword(s):  
Seismic Data ◽  
Structural Model ◽  
Mineral Exploration ◽  
Petroleum Exploration ◽  
Block Rotation ◽  
North West ◽  
The North ◽  
Northern Carnarvon Basin ◽  
Migration Pathways ◽  
Carnarvon Basin

The Barrow and Dampier Sub-basins of the Northern Carnarvon Basin developed by repeated reactivation of long-lived basement structures during Palaeozoic and Mesozoic tectonism. Inherited basement fabric specific to the terranes and mobile belts in the region comprise northwest, northeast, and north–south-trending Archaean and Proterozoic structures. Reactivation of these structures controlled the shape of the sub-basin depocentres and basement topography, and determined the orientation and style of structures in the sediments.The Lewis Trough is localised over a reactivated NEtrending former strike-slip zone, the North West Shelf (NWS) Megashear. The inboard Dampier Sub-basin reflects the influence of the fabric of the underlying Pilbara Craton. Proterozoic mobile belts underlie the Barrow Sub-basin where basement fabric is dominated by two structural trends, NE-trending Megashear structures offset sinistrally by NS-trending Pinjarra structures.The present-day geometry and basement topography of the basins is the result of accumulated deformation produced by three main tectonic phases. Regional NESW extension in the Devonian produced sinistral strikeslip on NE-trending Megashear structures. Large Devonian-Carboniferous pull-apart basins were introduced in the Barrow Sub-basin where Megashear structures stepped to the left and are responsible for the major structural differences between the Barrow and Dampier Sub-basins. Northwest extension in the Late Carboniferous to Early Permian marks the main extensional phase with extreme crustal attenuation. The majority of the Northern Carnarvon basin sediments were deposited during this extensional basin phase and the subsequent Triassic sag phase. Jurassic extension reactivated Permian faults during renewed NW extension. A change in extension direction occurred prior to Cretaceous sea floor spreading, manifest in basement block rotation concentrated in the Tithonian. This event changed the shape and size of basin compartments and altered fluid migration pathways.The currently mapped structural trends, compartment size and shape of the Barrow and Dampier Sub-basins of the Northern Carnarvon Basin reflect the “character” of the basement beneath and surrounding each of the subbasins.Basement character is defined by the composition, lithology, structure, grain, fabric, rheology and regolith of each basement terrane beneath or surrounding the target basins. Basement character can be discriminated and mapped with mineral exploration methods that use non-seismic data such as gravity, magnetics and bathymetry, and then calibrated with available seismic and well datasets. A range of remote sensing and geophysical datasets were systematically calibrated, integrated and interpreted starting at a scale of about 1:1.5 million (covering much of Western Australia) and progressing to scales of about 1:250,000 in the sub-basins. The interpretation produced a new view of the basement geology of the region and its influence on basin architecture and fill history. The bottom-up or basement-first interpretation process complements the more traditional top-down seismic and well-driven exploration methods, providing a consistent map-based regional structural model that constrains structural interpretation of seismic data.The combination of non-seismic and seismic data provides a powerful tool for mapping basement architecture (SEEBASE™: Structurally Enhanced view of Economic Basement); basement-involved faults (trap type and size); intra-sedimentary geology (igneous bodies, basement-detached faults, basin floor fans); primary fluid focussing and migration pathways and paleo-river drainage patterns, sediment composition and lithology.

Inferred seismic fault associated with the 1998 M = 6.2 Zhangbei-Shanyi earthquake, Hebei Province, China

1999 ◽  
Vol 89 (2) ◽  
pp. 550-554 ◽  
Author(s):  
Aiming Lin ◽  
Guochun Zhao ◽  
Guozhe Zhao ◽  
Xiwei Xu
Keyword(s):  
Seismic Data ◽  
Active Fault ◽  
Lateral Displacement ◽  
Displacement Component ◽  
The North ◽  
Seismic Fault ◽  
Direction Change ◽  
Western Side ◽  
Northwest Region ◽  
Beijing China

Abstract The shallow, Ms = 6.2, 1998 Zhangbei-Shanyi earthquake that affected the northwest region of Beijing, China, occurred at the intersection of two active fault zones, located on the north and east edges of the Ordos tableland. A detailed map of the intensity distribution of damaged building shows that the most damaged area was centered 8 to 10 km away from the epicenter, including an ellipsoidal region with a strike of NNE, where more than 70 to 90% of buildings were destroyed. Many chimneys and gate pillars were broken and fell toward the SSE-SSW direction in the western side of the most damaged area and to the NNE-NNW direction in the eastern side. Aftershocks were also concentrated in the most damaged area. It is inferred that the boundary of the downfallen direction change is the surface trace of the seismic fault. Based on the seismic data, the distribution of damaged buildings, and the downfallen directions of 70 chimneys and gate pillars, it is identified that the seismic fault is a thrust fault striking NNE and dipping 40° to 50° northwest with a large right-lateral displacement component.

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.

NORTH WEST SHELF 3-D SEISMIC—A DECADE OF DEVELOPMENTS

1993 ◽  
Vol 33 (1) ◽  
pp. 315
Author(s):  
P.S. Vaughan
Keyword(s):  
Joint Venture ◽  
Spatial Sampling ◽  
Seismic Surveys ◽  
North West ◽  
The North ◽  
Technological Developments

Woodside as Operator, on behalf of three Joint Venture groups, over the last decade has acquired eight 3-D seismic surveys covering some 4 600 km2 over the Rankin Trend and Dampier Sub-Basin Production Licences and Exploration Permits on the North West Shelf of Australia. This area represents approximately 45 per cent coverage of the present Woodside operated acreage in the area. The acquisition, processing and interpretation technology and also the benefits derived from the 3-D technique have changed remarkably since the first North West Shelf 3-D survey in 1981. This paper focusses on the main technological developments in 3-D seismic, particularly involving multi-source and streamer technology, increased spatial sampling and interpretation techniques which have changed the role of 3-D seismic in Exploration strategies through the 1980s and into the 1990s.

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.

Accuracy of wavelets, seismic inversion, and thin-bed resolution

2017 ◽  
Vol 5 (4) ◽  
pp. T523-T530
Author(s):  
Ehsan Zabihi Naeini ◽  
Mark Sams
Keyword(s):  
Seismic Data ◽  
Reservoir Characterization ◽  
Low Frequency ◽  
Seismic Inversion ◽  
Inversion Method ◽  
Frequency Content ◽  
Frequency Model ◽  
North West ◽  
The North ◽  
Well Data

Broadband reprocessed seismic data from the North West Shelf of Australia were inverted using wavelets estimated with a conventional approach. The inversion method applied was a facies-based inversion, in which the low-frequency model is a product of the inversion process itself, constrained by facies-dependent input trends, the resultant facies distribution, and the match to the seismic. The results identified the presence of a gas reservoir that had recently been confirmed through drilling. The reservoir is thin, with up to 15 ms of maximum thickness. The bandwidth of the seismic data is approximately 5–70 Hz, and the well data used to extract the wavelet used in the inversion are only 400 ms long. As such, there was little control on the lowest frequencies of the wavelet. Different wavelets were subsequently estimated using a variety of new techniques that attempt to address the limitations of short well-log segments and low-frequency seismic. The revised inversion showed greater gas-sand continuity and an extension of the reservoir at one flank. Noise-free synthetic examples indicate that thin-bed delineation can depend on the accuracy of the low-frequency content of the wavelets used for inversion. Underestimation of the low-frequency contents can result in missing thin beds, whereas underestimation of high frequencies can introduce false thin beds. Therefore, it is very important to correctly capture the full frequency content of the seismic data in terms of the amplitude and phase spectra of the estimated wavelets, which subsequently leads to a more accurate thin-bed reservoir characterization through inversion.

THE GOLDFIELDS GAS PIPELINE: 'OPENING A NEW FRONTIER'

1996 ◽  
Vol 36 (1) ◽  
pp. 599
Author(s):  
B.M. Ride
Keyword(s):  
Joint Venture ◽  
Major Effect ◽  
Gas Pipeline ◽  
Liquid Fuels ◽  
Mining Operations ◽  
Simple Method ◽  
North West ◽  
Demand Growth ◽  
The North ◽  
New Frontier

Gas exploration and development in the northwest Pilbara in WA has increased due to the commitment of the Goldfields Gas Transmission Joint Venture to a 1,380 km gas pipeline linking the north west Pilbara to the east Pilbara iron ore region and the northern and central Goldfields. Construction of the GGT pipeline was approved in January 1995 and it is expected the pipeline will be servicing major mining operations in Newman, Mt Keith, Leinster and Kalgoorlie by August 1996. Other existing mining operations located near the pipeline are expected to convert from distillate for power station fuel to gas in 1996-97. Major new mining prospects in these highly prospective minerals provinces also offer potential for increased gas demand and GGT Pipeline throughput.The commercial arrangements for GGT Pipeline services are the first in Australia to be offered under the open access arrangements espoused by the Federal and WA Governments, and have set a benchmark for other pipelines in Australia. The innovative distance related pipeline tariff arrangements offer prospective gas shippers a simple method for evaluating use of the GGT pipeline and securing gas transmission services.The GGT Pipeline has had and will continue to have a major effect on the WA gas scene, stimulating gas exploration by capturing an established base load energy market currently dependent on liquid fuels and stimulating further WA gas demand growth.

THE DEVELOPMENT OF GORGON AREA GAS

2002 ◽  
Vol 42 (2) ◽  
pp. 113
Author(s):  
I.J. Grose
Keyword(s):  
Natural Gas ◽  
Environmental Performance ◽  
Joint Venture ◽  
Unit Cost ◽  
Clean Energy ◽  
North West ◽  
Design Concepts ◽  
The North ◽  
Competitive Prices ◽  
Exxon Mobil

Australia will increasingly need to turn to natural gas to offset declining oil production and meet an expanding global need for clean energy. The Gorgon Development Joint Venture Participants, (ChevronTexaco/Exxon- Mobil/Shell), are poised to develop the significant Gorgon gas reserves located 130 km offshore the North West Australian coast to help fulfil this need.The Gorgon Development has access to extensive proved reserves of 13.8 Tcf and a development plan that can supply gas to a Barrow Island landfall at world competitive prices. Several concepts are being considered for development of the Gorgon reserves.Technology will play a key role, with the extensive use of subsea production facilities and innovative LNG design concepts being considered.The focus is on a design that would have a low unit cost and also provide new benchmarks in safety and environmental performance. The development of the Gorgon reserves could also facilitate the establishment of other gas-based industries in Western Australia and offers the opportunity for new gas-to-liquid (GTL) plants to lead Australia’s transition to a gas-based economy.The Gorgon Development is expected to attract nearly A$4 billion investment for an LNG development and a further A$2 billion for a major industrial gas consumer. Total export income could reach A$2,500 million per year for 30 years.

SEISMIC DELINEATION OF STRUCTURE-CONTROLLED CARBONATE CEMENT AND POTENTIAL ECONOMIC IMPLICATIONS, ANGEL FIELD, NORTH WEST SHELF

1995 ◽  
Vol 35 (1) ◽  
pp. 280
Author(s):  
S. Ryan-Grigor ◽  
J.P. Schulz-Rojahn
Keyword(s):  
Seismic Data ◽  
High Amplitude ◽  
Fault System ◽  
3D Seismic ◽  
Economic Implications ◽  
Northern Margin ◽  
North West ◽  
The North ◽  
Migration Pathways ◽  
3D Seismic Data

Major carbonate-cemented zones occur in Late Jurassic Angel Formation sandstones of marine mass flow origin that contain large hydrocarbon reserves in the Angel Field, Dampier Sub-basin. Preliminary results suggest that poikilotopic dolomite cement is dominant. The carbonate-cemented zones are identifiable from wireline log response and 3D seismic data, and occur in discrete intervals with a cumulative thickness of approximately 165m at Angel-2. These intervals produce a zone of high amplitude reflections of about 100 ms two-way time. Field-wide seismic mapping indicates that these carbonate-cemented zones sharply abut the northern margin of a major east-west trending strike-slip fault system that traverses this field. The carbonate-cemented zones extend in a wedge-like shape towards the northeast and concentrate along the crest of the main structural trend.The results underscore the importance of 3D seismic data for a better estimation of reservoir risk and reserves in variably carbonate-cemented sandstones.The carbonate-cemented zones may represent a 'plume' related to migration of petroleum and/or carbon dioxide. Therefore delineation of major carbonate-cemented zones using seismic data may aid in the identification of petroleum migration pathways and pools in the North West Shelf. Alternatively, carbonate cements dissolved south of the major fault zone and possibly in downdip locations in which case dissolution pores may exist in these areas. Further research is required to evaluate these hypotheses.

LEGENDRE: MATURATION OF A MARGINAL OFFSHORE OIL DISCOVERY TO DEVELOPMENT PROJECT

1999 ◽  
Vol 39 (1) ◽  
pp. 504
Author(s):  
J.M. Willetts ◽  
D.J. Mason ◽  
L. Guerrera ◽  
P. Ryles
Keyword(s):  
Joint Venture ◽  
Development Planning ◽  
Development Project ◽  
Horizontal Drilling ◽  
North West ◽  
The North ◽  
Simulation Techniques ◽  
Production Wells ◽  
Light Oil ◽  
Offshore Oil

Commercialisation of the Legendre hydrocarbon resources represents the culmination of over 30 years of exploration and appraisal and more recent development planning, following the discovery by the first well to be flow-tested on the North West Shelf, Legendre–1, in 1968. By application of 3D seismic, reservoir modelling and simulation techniques, horizontal drilling and innovative development options, the WA-l-P Joint Venture is confident of achieving an economic return on a relatively small resource base.The two separate accumulations, Legendre North and Legendre South, are together expected to contain some 14 million m3 (90 MMSTB) of oil-in-place. The oil column in the northern accumulation is 45 m at its maximum, whilst a 20 m column is present in the southern accumulation. Reservoir quality is generally very good with mostly massive sandstones with little or no internal stratification. The reservoir contains a light oil and aquifer support is expected from communication with the underlying Angel Formation sandstones.The subsurface development plan has been designed to optimise the recovery of the oil in place in the two accumulations. Production wells with horizontal sections of 750 m will be used to minimise drawdown and ensure good sweep. Production is expected at a plateau rate of 4,800 to 6,400 m3/d (30−40,000 BOPD). Produced gas will be disposed of by means of a re-injection well downdip of the producers.

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