FORMATION EVALUATION IN HIGHLY-DEVIATED, LONG REACH DEVELOPMENT WELLS ON THE NORTH RANKIN GAS FIELD, NW SHELF, AUSTRALIA

1990 ◽  
Vol 30 (1) ◽  
pp. 310
Author(s):  
D. Lasserre
Keyword(s):  
Drilling Fluid ◽  
Drill Pipe ◽  
Vertical Resolution ◽  
Gas Field ◽  
Log Data ◽  
Formation Evaluation ◽  
North West ◽  
The North ◽  
Reservoir Description ◽  
Resistivity Log

A large proportion of the North West Shelf development gas wells are long reach (greater than 3500 m) and highly deviated. For reservoir description and management purposes, comprehensive formation evaluation needs to be carried out in these wells.Considerable difficulties have been encountered with electric log data acquisition due to friction and borehole conditions in these long, highly-deviated wells. As a result, new techniques to log the zones of interest were introduced. A system using the drill pipe to transport the downhole logging tools has been successfully used.Also, low-toxicity oil-based mud (LTM) was introduced in order to ease drilling problems and borehole conditions. However, owing to the non-conductive nature of the oil-based drilling fluid, improvements were required in the vertical resolution of the resistivity measurements and the estimation of the formation porosity.A computer program using a forward deconvolution technique recently developed by Shell's research laboratory in Holland has been successfully applied to enhance the vertical resolution of the resistivity log reading.The large range of uncertainty on the pore volume has been reduced to reasonable level by calibrating the porosity log data against core data obtained in a well drilled with LTM.

JOHN BROOKES GAS FIELD DEVELOPMENT

2005 ◽  
Vol 45 (1) ◽  
pp. 13
Author(s):  
A.J. McDiarmid ◽  
P.T. Bingaman ◽  
S.T. Bingham ◽  
B. Kirk-Burnnand ◽  
D.P. Gilbert ◽  
...  
Keyword(s):  
Low Cost ◽  
Time Frame ◽  
Gas Production ◽  
Gas Field ◽  
Initial Development ◽  
North West ◽  
Field Development ◽  
The North ◽  
Production Wells ◽  
Development Approach

The John Brookes gas field was discovered by the drilling of John Brookes–1 in October 1998 and appraisal drilling was completed in 2003. The field is located about 40 km northwest of Barrow Island on the North West Shelf, offshore West Australia. The John Brookes structure is a large (>90 km2) anticline with >100 m closure mapped at the base of the regional seal. Recoverable sales gas in the John Brookes reservoir is about 1 Tcf.Joint venture approval to fast track the development was gained in January 2004 with a target of first gas production in June 2005. The short development time frame required parallel workflows and use of a flexible/low cost development approach proven by Apache in the area.The John Brookes development is sized for off-take rates up to 240 TJ/d of sales gas with the development costing A$229 million. The initial development will consist of three production wells tied into an unmanned, minimal facility wellhead platform. The platform will be connected to the existing East Spar gas processing facilities on Varanus Island by an 18-inch multi-phase trunkline. Increasing the output of the existing East Spar facility and installation of a new gas sweetening facility are required. From Varanus Island, the gas will be exported to the mainland by existing sales gas pipelines. Condensate will be exported from Varanus Island by tanker.

THE ROLE OF AMPLITUDE VERSUS OFFSET TECHNOLOGY IN PROMOTING OFFSHORE PETROLEUM EXPLORATION IN AUSTRALIA

2007 ◽  
Vol 47 (1) ◽  
pp. 163 ◽  
Author(s):  
P. E. Williamson ◽  
F. Kroh
Keyword(s):  
Petroleum Exploration ◽  
Gas Field ◽  
North West ◽  
Preliminary Results ◽  
Exmouth Plateau ◽  
The North ◽  
Amplitude Versus Offset ◽  
Cable Lines ◽  
The Cost ◽  
Amplitude Versus

Amplitude versus offset (AVO) technology has proved itself useful in petroleum exploration in various parts of the world, particularly for gas exploration. To determine if modern AVO compliant processing could identify potential anomalies for exploration of open acreage offshore Australia, Geoscience Australia reprocessed parts of four publicly available long cable lines. These lines cover two 2006 acreage release areas on the Exmouth Plateau and in the Browse Basin on the North West Shelf. An earlier study has also been done on two publicly available long cable lines from Geoscience Australia’s Bremer Basin study and cover areas from the 2005 frontier acreage release on the southern margin. The preliminary results from these three reprocessing efforts produced AVO anomalies and were made publicly available to assist companies interested in assessing the acreage. The results of the studies and associated data are available from Geoscience Australia at the cost of transfer.The AVO data from the Exmouth Plateau show AVO anomalies including one that appears to be at the Jurassic level of the reservoir in the Jansz/Io supergiant gas field in adjacent acreage to the north. The AVO data from the Caswell Sub-basin of the Browse Basin show an AVO anomaly at or near the stratigraphic zone of the Brecknock South–1 gas discovery to the north. The geological settings of strata possibly relating to two AVO anomalies in the undrilled Bremer Basin are in the Early Cretaceous section, where lacustrine sandstones are known to occur. The AVO anomalies from the three studies are kilometres in length along the seismic lines.These preliminary results from Geoscience Australiaand other AVO work that has been carried out by industry show promise that AVO compliant processing has value—particularly for gas exploration offshore Australia—and that publicly available long-cable data can be suitable for AVO analysis.

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.

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.

THE DEVELOPMENT AND EARLY PERFORMANCE OF THE NORTH RANKIN FIELD

1986 ◽  
Vol 26 (1) ◽  
pp. 420
Author(s):  
F.M. Posaner ◽  
W.H. Goldthorpe
Keyword(s):  
Liquefied Natural Gas ◽  
Processing Capacity ◽  
Domestic Consumption ◽  
Gas Field ◽  
North West ◽  
The North ◽  
And Performance ◽  
Early Performance ◽  
Current Stage ◽  
Gas Recycling

The North Rankin gas field is the first field to be developed as part of the North West Shelf Project and has now been on stream for some two years. With a most likely gas-initially-in-place of 11TCF (308 × 109 m3), it is the largest appraised gas-condensate field in Australia.At the current stage, gas is being produced from one platform (the North Rankin 'A' platform) entirely for domestic consumption. Future development involves the drilling of additional wells to provide gas for export as liquefied natural gas (LNG) to Japan, installation of a second platform, and construction of an additional onshore plant to manufacture the LNG. In addition, a gas recycling project is to be implemented on the North Rankin 'A' platform to increase the recovery of condensate by utilizing spare platform processing capacity available prior to reaching plateau LNG exports.The present paper reviews the development and performance of this major field over the first two years of its producing life. Emphasis is placed on the reservoir pressure performance, particularly in relation to the reservoir geology.

HARRIET GAS GATHERING PROJECT, BARROW SUB-BASIN

1992 ◽  
Vol 32 (1) ◽  
pp. 56
Author(s):  
Adrian Williams ◽  
Dave Macey
Keyword(s):  
Offshore Platforms ◽  
Gas Field ◽  
North West ◽  
Associated Gas ◽  
The North ◽  
Wet Gas ◽  
Start Up ◽  
New Development ◽  
Transmission Pipeline ◽  
Gas Fields

Since start-up of Harriet oil production in early 1986, the TL/1 joint venturers have attempted to find a use for the oil-associated gas as well as other gas from neighbouring small gas fields. Initially, supplies from the North West Shelf Project were well in excess of local demand and acted as a damper on new development projects. With time, however, gas reserves in the Harriet area were augmented through new discoveries and the State's demand grew steadily until, in mid 1990, a new project could be justified. In December 1990, an agreement was reached with the State Energy Commission of Western Australia (SECWA) for the supply of 140 PJ (123 BCF) of gas over a ten year period, with an option for a further 65 PJ (57 BCF). First gas supplies are planned for June 1992.The project is based on the supply of Harriet solution gas as well as free gas from the Campbell, Sinbad and Rosette fields. Bambra is a potential future addition but is not required initially for the contract.The project involves small offshore platforms at Campbell and Sinbad, a wet gas pipeline from these platforms to Varanus Island, a facility on the Island to dry the gas and boost the pressure, and a transmission line to SECWA's system, approximately 100 km distant.The transmission pipeline has considerable reserve capacity over the initial contract flowrate of 30 to 60 TJ/day (26 to 52 MMCFGD) and provides a basis for further small gas projects utilising either flare gas from new oil developments or new gas field developments.

THE NORTH WEST SHELF

1989 ◽  
Vol 29 (1) ◽  
pp. 529 ◽  
Author(s):  
A.E. Cockbain
Keyword(s):  
Oil Fields ◽  
Gas Field ◽  
North West ◽  
Canning Basin ◽  
The North ◽  
The Indian Ocean ◽  
Northern Carnarvon Basin ◽  
Siliciclastic Sediments ◽  
Breakup Unconformity ◽  
Carnarvon Basin

The region of the North West Shelf dealt with in this paper is underlain by three of the four basins which make up the Westralian Superbasin. The Bonaparte Basin lies outside the scope of this paper; the other basins are the Browse Basin, the offshore Canning Basin, here named the Western Canning Basin, and the offshore Carnarvon Basin, here called the Northern Carnarvon Basin. Sediments belonging to ten depositional sequences (Pz5, Mzl to Mz5, and Czl to Cz4) are present in the basins, the oldest being of Late Carboniferous and Permian age (Pz5).Deposition commenced in rift (interior fracture) basins under fluvial/deltaic conditions in the Late Permian/Early Triassic (Mzl), when the North West Shelf was part of Gondwana. Continental breakup took place in the Middle Jurassic (breakup unconformity between Mz2 and Mz3), and marine conditions prevailed over the Westralian Superbasin thereafter, with deposition taking place in a marginal sag setting. Siliciclastic sediments gave place to carbonates in the Late Cretaceous (Mz5) as the Indian Ocean grew larger.Parts of the area have been under permit since 1946, and to date some 227 exploration wells have been drilled. The most intensive exploration has taken place in the Northern Carnarvon Basin (191 wells), followed by the Browse Basin (20 wells), and Western Canning Basin (16 wells). Thirty- four economic and potentially economic discoveries have been made. The main target reservoirs are Triassic, Jurassic and Cretaceous, and the regional seals are Triassic and Cretaceous. The fields are of two types: pre- breakup unconformity (mainly tilted horst blocks), and post- breakup unconformity (usually four- way dip closures). Of the five producing fields, the North Rankin Gas Field is a pre- breakup field, while the four oil fields (Barrow, Harriet, South Pepper and North Herald) are all post- breakup.

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.

Application of formation pressure while drilling in Australia: North West Shelf examples

2009 ◽  
Vol 49 (2) ◽  
pp. 568
Author(s):  
Dmitry Molohkov ◽  
Andy Pietsch ◽  
Jack Harfoushian ◽  
Shahid Azizul Haq
Keyword(s):  
Drill Pipe ◽  
Cost Effective ◽  
Lessons Learned ◽  
Formation Pressure ◽  
Well Control ◽  
North West ◽  
Service Companies ◽  
The North ◽  
Essential Input ◽  
Formation Pore Pressure

Since its introduction in the 1950s, the point-by-point wireline formation pressure measurement technique has been successfully used for formation evaluation and reservoir management, and has been an essential input into reservoir models. In exploration and appraisal wells, where depletion has not yet affected the reservoir, vertical pressure profiling can be used for fluid gradient determination that may be interpreted in terms of fluid densities and contacts. In a dynamic producing environment pressure measurements can help to identify vertical and horizontal boundaries and communication. Measurement of pressure distribution along the borehole was historically done with wireline instruments or, in difficult logging conditions, with wireline instruments conveyed by drill pipe. In some environments, especially in highly deviated and S-shaped wells or unconsolidated formations, drill pipe conveyance of wireline formation pressure testers introduces significant operational risk. Formation Pressure While Drilling (FPWD), introduced in 2003, offers a new cost-effective solution for gathering formation pressure data. FPWD is a new method to directly measure formation pore pressure as the well is being drilled, extending its application beyond traditional fluid typing, contacts and compartmentalisation determination to well control and drilling optimisation. The market for FPWD is developing rapidly with all major service companies providing their own implementations of the technology. The next step in the evolution of FPWD technology—sampling while drilling—is not commercially available yet, but this is just a matter of time. The case history presented in this extended abstract is an example of the application and lessons learned from the FPWD service used in one of the oil fields on the North West Shelf, Australia.

PERTH BASIN REJUVENATED

1992 ◽  
Vol 32 (1) ◽  
pp. 33 ◽  
Author(s):  
Peter B. Hall ◽  
Robert L. Kneale
Keyword(s):  
Natural Gas ◽  
Western Australia ◽  
Market Access ◽  
Field Size ◽  
Gas Field ◽  
North West ◽  
The North ◽  
New Concepts ◽  
Technological Developments ◽  
Gas Market

The northern Perth Basin is an area where recent seismic advances combined with new geological insight, have led to exploration success with a significant new gas field discovery at Beharra Springs and a number of other minor discoveries. This paper outlines 'new concepts' with regard to stratigraphy and structure and how this has been balanced with the commercial environment to rejuvenate exploration in the northern Perth Basin. The Perth Basin is unique in Australia, as running through the middle of the Basin is the West Australian Natural Gas (WANG) pipeline which will be operating at approximately 26 per cent of its capacity in 1992. With the deregulation of the natural gas market in 1988, supply of gas to the Western Australian market via the State Energy Commission of Western Australia (SECWA) pipeline from the Carnarvon Basin, and in particular, the North West Shelf project, can now be balanced with supply from the onshore Perth Basin carried by the WANG pipeline.The minimum economically viable gas field in the northern Perth Basin is calculated to be 15 BCF (16.05 PJ) and the expected median field size is 50 BCF (53.5 PJ) of recoverable gas. Based on the historical success rate of one in eight, typical finding costs are 12 c/MCF (12 c/GJ).In the 1990/91 financial year, eight onshore exploration wells were drilled in Western Australia of which five were drilled in the northern Perth Basin. Provided the market access and opportunities remain, it is anticipated that the recent technological developments will sustain exploration and development of the onshore northern Perth Basin.

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