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.

New insights into North Sea tunnel valley infill and genesis from high-resolution 3D seismic data

2020 ◽  
Author(s):  
James Kirkham ◽  
Kelly Hogan ◽  
Robert Larter ◽  
Ed Self ◽  
Ken Games ◽  
...  
Keyword(s):  
High Resolution ◽  
North Sea ◽  
Seismic Data ◽  
3D Seismic ◽  
Seismic Reflection Data ◽  
North West ◽  
The North ◽  
Reflection Data ◽  
Order Of Magnitude ◽  
Subglacial Meltwater

<p>Tunnel valleys are large (kilometres wide, hundreds of metres deep) channels incised into bedrock and soft sediments by the action of pressurised subglacial meltwater. Discovered over a century ago, they are common across large swathes of North-West Europe and North America. However, many aspects of tunnel valley formation, and the processes by which they are infilled, remain poorly understood. Here, we use new high-resolution 3D seismic reflection data, collected by the geohazard assessment industry, to examine the infill lithology and architecture of buried tunnel valleys located in the central North Sea. The spatial resolution of our seismic data (3.125-6.25 m bin size) represents an order of magnitude improvement in the data resolution that has previously been used to study tunnel valleys in this region, allowing us to examine their infill in unprecedented detail. Inside the tunnel valleys, we identify a suite of buried subglacial landforms, some of which have rarely been reported inside tunnel valleys before. These landforms include a 14-km-long system of segmented eskers, crevasse-squeeze ridges, subsidiary meltwater channels and retreat moraines. Their presence suggests that, in some cases, tunnel valleys in the North Sea were reoccupied by ice following their initial formation, casting doubt on hypotheses which invoke catastrophic releases of water to explain tunnel valley creation.</p>

DEVELOPMENT OF THE NORTH RANKIN FIELD, NORTH WEST SHELF, AUSTRALIA

1983 ◽  
Vol 23 (1) ◽  
pp. 164
Author(s):  
M. David Agostini
Keyword(s):  
Seismic Survey ◽  
Process Equipment ◽  
Two Phase ◽  
Gas Field ◽  
North West ◽  
The North ◽  
Christmas Trees ◽  
High Level ◽  
Inflow Performance ◽  
Standard Steel

The North Rankin gas field discovered in 1971, has been evaluated by a series of appraisal wells and refinement of this is underway through the use of a 3D seismic survey. Extensive production testing on two wells was used to establish reservoir fluid characteristics, inflow performance and to predict reservoir behaviour.The North Rankin 'A' platform has been constructed of a standard steel jacket design. Components of the structure were built in Japan, Singapore, Geraldton, Jervoise Bay and Adelaide. Provision exists for 34 wells to be drilled from the structure to exploit the southern end of the North Rankin field.Simultaneous drilling and producing activities are planned, requiring well survey and deviation control techniques that will provide a high level of confidence. Wells will be completed using 7 inch tubing, fire resistant christmas trees, and are designed to be produced at about 87 MMSCFD on a continuous basis. Process equipment on this platform is designed to handle 1200 MMSCFD and is intended primarily to dry the gas and condensate and to transfer gas and liquid to shore in a two phase 40 inch pipeline. The maintenance of offshore equipment is being planned to maximise the ratio between planned and unplanned work.The commencement of drilling activities is planned for mid 1983, with commissioning of process equipment occurring in the second quarter of 198 The North Rankin 'A' platform will initially supply the WA market at some 400 MMSCFD offshore gas rate, requiring 7 wells. The start of LNG exports is planned for April 1987. The intial gas for this will be derived from the North Rankin 'A' platform.

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.

The Brunei slide: A giant submarine landslide on the North West Borneo Margin revealed by 3D seismic data

2007 ◽  
Vol 246 (1) ◽  
pp. 9-23 ◽  
Author(s):  
M.J.R. Gee ◽  
H.S. Uy ◽  
J. Warren ◽  
C.K. Morley ◽  
J.J. Lambiase
Keyword(s):  
Seismic Data ◽  
Submarine Landslide ◽  
3D Seismic ◽  
North West ◽  
The North ◽  
3D Seismic Data

The Johnston Gas Field, Blocks 43/26a, 43/27a, UK Southern North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 749-759 ◽  
Author(s):  
David E. Lawton ◽  
Paul P. Roberson
Keyword(s):  
North Sea ◽  
Development Plan ◽  
Seismic Survey ◽  
3D Seismic ◽  
Seismic Attribute ◽  
Gas Field ◽  
Southern North Sea ◽  
North East ◽  
The North ◽  
The Uk

abstractThe Johnston Field is a dry gas accumulation located within blocks 43/26a and 43/27a of the UK Southern North Sea. The discovery well was drilled in 1990 and after the drilling of one appraisal well in 1991, a development plan was submitted and approved in 1993. Initially two development wells were drilled from a four slot sub-sea template, with commercial production commencing in October 1994. A further horizontal development well was added to the field in 1997.The field has a structural trap, fault bounded to the SW and dip-closed to the north, east and south. This field geometry has been established using high quality 3D seismic data, enhanced by seismic attribute analysis. The sandstone reservoir interval consists of the Early Permian, Lower Leman Sandstone Formation of the Upper Rotliegend Group. This reservoir consists of a series of interbedded aeolian dune, fluvial, and clastic sabkha lithofacies. The quality of the reservoir is variable and is principally controlled by the distribution of the various lithofacies. The top seal and fault bounding side seal are provided by the overlying clay stone of the Silverpit Shale Formation and the evaporite dominated Zechstein Supergroup.The field has been developed using a phased development plan, with the acquisition of a 3D seismic survey allowing for the optimized drilling of a high deliverability horizontal well.Current mapped gas initially-in-place estimates for the field are between 360 and 403 BCF, with an estimated recovery factor of between 60 and 75%.

scholarly journals Deep crustal structure of the North-West African margin from combined wide-angle and reflection seismic data (MIRROR seismic survey)

2015 ◽  
Vol 656 ◽  
pp. 154-174 ◽  
Author(s):  
Y. Biari ◽  
F. Klingelhoefer ◽  
M. Sahabi ◽  
D. Aslanian ◽  
P. Schnurle ◽  
...  
Keyword(s):  
Crustal Structure ◽  
Seismic Data ◽  
West African ◽  
Seismic Survey ◽  
Wide Angle ◽  
North West ◽  
Reflection Seismic ◽  
The North ◽  
Deep Crustal Structure

scholarly journals Geohazard detection using 3D seismic data to enhance offshore scientific drilling site selection

2020 ◽  
Vol 28 ◽  
pp. 1-27 ◽  
Author(s):  
David R. Cox ◽  
Paul C. Knutz ◽  
D. Calvin Campbell ◽  
John R. Hopper ◽  
Andrew M. W. Newton ◽  
...  
Keyword(s):  
Site Selection ◽  
Seismic Data ◽  
Seismic Survey ◽  
3D Seismic ◽  
Seismic Reflection Data ◽  
Scientific Drilling ◽  
The North ◽  
Reflection Data ◽  
3D Seismic Data ◽  
Geohazard Assessment

Abstract. A geohazard assessment workflow is presented that maximizes the use of 3D seismic reflection data to improve the safety and success of offshore scientific drilling. This workflow has been implemented for International Ocean Discovery Program (IODP) Proposal 909 that aims to core seven sites with targets between 300 and 1000 m below seabed across the north-western Greenland continental shelf. This glaciated margin is a frontier petroleum province containing potential drilling hazards that must be avoided during drilling. Modern seismic interpretation techniques are used to identify, map and spatially analyse seismic features that may represent subsurface drilling hazards, such as seabed structures, faults, fluids and challenging lithologies. These hazards are compared against the spatial distribution of stratigraphic targets to guide site selection and minimize risk. The 3D seismic geohazard assessment specifically advanced the proposal by providing a more detailed and spatially extensive understanding of hazard distribution that was used to confidently select eight new site locations, abandon four others and fine-tune sites originally selected using 2D seismic data. Had several of the more challenging areas targeted by this proposal only been covered by 2D seismic data, it is likely that they would have been abandoned, restricting access to stratigraphic targets. The results informed the targeted location of an ultra-high-resolution 2D seismic survey by minimizing acquisition in unnecessary areas, saving valuable resources. With future IODP missions targeting similarly challenging frontier environments where 3D seismic data are available, this workflow provides a template for geohazard assessments that will enhance the success of future scientific drilling.

IMPROVEMENTS IN SEISMIC IMAGING, IO JANSZ GAS FIELD NORTH WEST SHELF, AUSTRALIA

2006 ◽  
Vol 46 (1) ◽  
pp. 135
Author(s):  
J. Hefti ◽  
S. Dewing ◽  
C. Jenkins ◽  
A. Arnold ◽  
B.E. Korn
Keyword(s):  
Image Quality ◽  
Processing Parameters ◽  
Interdisciplinary Teams ◽  
Seismic Survey ◽  
Gas Field ◽  
North West ◽  
The North ◽  
Seismic Acquisition ◽  
History Of ◽  
Close Cooperation

The Io Jansz gas field is situated in the Carnarvon Basin on the North West Shelf of Australia. It is Australia’s largest gas field, estimated to hold over 20 TCF of gas reserves and covering an area of over 2000 km2. Following a series of appraisal wells and a 3D seismic survey, this field is moving rapidly towards development. Image quality of the 3D provided significant uplift over existing 2D surveys in the area. Expectations for resolution and business targets have been met through careful planning and the provision of staged deliverables.Despite the exceptional data quality, a number of technical challenges were encountered that led to operational changes and adaptations by the project team. Source height statics and severe image distortion due to overburden are examples of some of the challenges addressed. Consideration of the exploration history of this field and its associated imaging gives insight into the improvements in image quality that can be realised by careful selection of acquisition and processing parameters, high levels of quality control (QC) and modern processing algorithms. The ultimate success of this project was achieved through close cooperation within interdisciplinary teams comprised of partner technical staff and the seismic acquisition and processing contractor.

LARGE-BORE GAS WELL DESIGN—APPLICATION TO OFFSHORE GAS FIELD DEVELOPMENT

2006 ◽  
Vol 46 (1) ◽  
pp. 79
Author(s):  
F. Thompson ◽  
I. Terziev ◽  
I. Taggart
Keyword(s):  
New Technologies ◽  
Capital Expenditure ◽  
Large Diameter ◽  
Gas Wells ◽  
Gas Field ◽  
Gas Well ◽  
North West ◽  
Field Development ◽  
The North ◽  
Trade Offs

Offshore gas development projects including the North West Shelf of Australia continue to develop new technologies in order to reduce development costs. Given that the number of development wells directly relates to capital expenditure, past attempts have focussed on obtaining higher gas rates out of conventional well designs by carefully managing erosional limits, which, in turn, tend to restrict the use of higher offtake rates.A strategy based on safely flowing gas wells at higher rates results in fewer wells and delays the phasing-in of additional wells, both of which result in economic enhancement. In recent times the industry has increasingly moved to large-bore gas well technology as a means of realising this strategy. Large-bore gas wells are defined as wells equipped with production tubing and flow control devices larger than 7” or 177 mm. Originally developed for land-based operations, this technology is increasingly moving offshore into totally subsea systems. One factor limiting the speed of adoption of this technology is the trade-off that exists between the increased offtake rates offered by large-bore systems and the risks posed by wear due to erosion in and around the wellhead area caused by any solids entrained in the gas stream.The problem becomes more acute when different-sized well designs employ the same wellhead configurations, because the upper wellhead area is usually the critical and limiting wear component.This paper summarises the recent developments in large-bore offshore applications and presents a consistent methodology showing how different gas well designs can be compared using hydraulic and erosional considerations. Additional trade-offs posed by reliable solids monitoring and the adoption of untested wellhead and intervention designs are discussed. In many cases, hybrid designs based on large diameter tubulars but with conventional wellheads may offer a useful balance between higher well rates and adoption of proven technology. The results shown here are directly applicable to alternative well designs presently under consideration for a number of offshore reservoir developments.

PORT CAMPBELL REVIEWED: METHANE AND CHAMPAGNE

1995 ◽  
Vol 35 (1) ◽  
pp. 418 ◽  
Author(s):  
J.D. Foster ◽  
A.J. Hodgson
Keyword(s):  
Late Cretaceous ◽  
Seismic Survey ◽  
Data Sets ◽  
3D Seismic ◽  
Gas Field ◽  
Natural Gas Markets ◽  
The North ◽  
Industrial Markets ◽  
Western Victoria ◽  
Gas Fields

Gas fields in the Port Campbell Embayment cur­rently supply all the natural gas markets (non-LPG) in western Victoria as well as commercial quanti­ties of carbon dioxide (C02) to industrial markets. Initial discoveries made between 1979 and 1981 were brought on-stream in 1986 with production from the North Paaratte field. Another substantial discovery was made in 1988, the Iona gas field, followed by the Boggy Creek C02 field in 1991, then the My lor and Langley fields in 1994. Discovery of Mylor marked the first recovery of oil from the Late Cretaceous Waarre Formation. Extensive 2D seis­mic data sets have been recorded in the region since 1979, and the first 3D seismic survey in the Otway Basin was carried out in 1993 extending beyond the area of the initial discoveries. No data on the fields have been published for nearly a decade and little detail about the structural and stratigraphic geol­ogy of the Late Cretaceous in the area has been documented. Summaries of the fields are presented incorporating many insights gained from interpre­tation of the 3D seismic data and its verification by the 'rotary lie detector'.

Sign in / Sign up

Export Citation Format

Share Document