NEW TECHNOLOGY—A MAJOR IMPACT ON A PRODUCING FIELD: NORTH RANKIN GAS FIELD, NORTH WEST SHELF, AUSTRALIA

1992 ◽  
Vol 32 (1) ◽  
pp. 20
Author(s):  
L. Tilbury ◽  
T. Barter
Keyword(s):  
New Technology ◽  
Development Planning ◽  
Geological Structure ◽  
Lower Jurassic ◽  
Production Performance ◽  
Amplitude Analysis ◽  
Gas Field ◽  
North West ◽  
The North ◽  
Drilling Technology

New technology, especially the significant advances in 3D seismic interpretation techniques and drilling technology, has had a major impact on the development planning for the North Rankin Field.Significant advances have been made through the application of: horizon attribute processing, seismic amplitude analysis and long-reach drilling technology.Horizon attribute processing, including image processing techniques, has led to a better understanding of the structurally complex region on the northern flank of the field. These studies, coupled with new geological concepts related to opposing fault regimes, have concluded that good reservoir communication should exist across a fault zone previously thought to subdivide the field into compartments. The drilling of expensive, long-reach wells into the northern sector has thus been deferred, and may never be required, because of the newly developed structural model.Seismic amplitude analysis, coupled with geological modelling, upgraded the North Rankin West area and culminated in the recent significant appraisal/development well NRA22. This well was drilled from the North Rankin 'A' (NRA) platform to a target outside the main North Rankin Field in the adjacent Searipple Graben. NRA22 encountered well developed gas-bearing sands of Bathonian age which flowed at high rates (140 MMSCFGD).The application of long-reach drilling technology within Woodside has also had significant impact on development planning. The original development plan for North Rankin included a second platform in the northeast of the field. Better than expected production performance from NRA, related to across-fault reservoir communication, removed the necessity for a second platform. Large gas reserves in the Lower Jurassic 'NC' unit in the northeast have, however, required dedicated wells to improve ultimate recovery from this unit. The drilling of long-reach wells (at record drift) into the NC unit has provided better access to these reserves.Although North Rankin has been producing for over seven years with a total of 23 development wells drilled, understanding of the geological structure is still being improved by using new technology and ideas.

SEISMIC AMPLITUDE ANALYSIS: AN END TO FIELD APPRAISAL?

1988 ◽  
Vol 28 (1) ◽  
pp. 144
Author(s):  
Larry A. Tilbury ◽  
Philip M. Smith
Keyword(s):  
Seismic Reflection ◽  
Development Planning ◽  
Late Triassic ◽  
Amplitude Analysis ◽  
Gas Field ◽  
North West ◽  
Field Development ◽  
Seismic Amplitude ◽  
The North ◽  
Prediction Techniques

The success of lateral prediction techniques based on seismic reflection amplitude analysis has had a significant impact upon recent appraisal and development planning strategies in the Coodwyn Gas Field, offshore north-western Australia.The Coodwyn structure is one of a series of major tilted fault blocks on the Rankin Trend. The gently dipping reservoir sequence of Late Triassic to earliest Jurassic age is truncated by a major erosional unconformity and is overlain by sealing Cretaceous sediments. It is situated some SO kilometres west- south-west of the producing North Rankin Gas Field, to which it bears a striking resemblance in structural form and reservoir stratigraphy. Eight appraisal wells have been drilled in and around the field since its discovery in 1971. The most recent appraisal drilling campaign was designed to test a possible northern extension of the field within a stratigraphically younger reservoir sequence than that previously seen. The success of this campaign was such that the northern Coodwyn reservoirs are now being evaluated as possible candidates for development from a Coodwyn Platform to provide gas for the North West Shelf Project - one of the largest and most ambitious natural resource developments yet undertaken in Australia.During the latest campaign it was confirmed that seismic reflection amplitudes at the Main Unconformity were directly related to the lithology and fluid content of the subcropping reservoir sequence. This has allowed the gas-bearing sands to be mapped across the field with far greater confidence than was previously possible, obviating the need for further appraisal drilling. In fact, Coodwyn -10, a well proposed to intersect the unappraised upper F sands, was not drilled because of the confidence placed in the amplitude map.The amplitude map was used extensively during the 1986 drilling campaign, for refining the structural interpretation of the field, and during the recent Goodwyn Field development planning for the targeting of notional development wells from possible platform locations.

Walkabove VSP with seismic-while-drilling technology: flawless operation in a highly deviated well

2013 ◽  
Vol 53 (2) ◽  
pp. 454
Author(s):  
Adrian Cristian Sanchez Rodriguez ◽  
Leon Dahlhaus ◽  
Konstantin Galybin ◽  
Andrew Vigor ◽  
Grant Skinner ◽  
...  
Keyword(s):  
Seismic Profile ◽  
Geological Structure ◽  
Surface Source ◽  
North West ◽  
The North ◽  
Bottom Hole ◽  
Surface Time ◽  
Drilling Technology ◽  
Bottom Hole Assembly

SWD was recently used in the North West Shelf of Australia to acquire time-depth measurements and to obtain a vertical seismic profile (VSP) while pulling out of hole. The use of SWD technology greatly enhanced the understanding of geology by acquiring a more precise geophysical picture of the subsurface, leading to better understanding of the subsurface and placement of wells in the future. A vertical incidence VSP was acquired in an offshore deviated well for a client on the Australian North West Shelf. The data was acquired using a moving-surface source, suspended from a boat, and a four-component downhole sensor in the bottom hole assembly (BHA). The downhole data was acquired using three orthogonal geophones and a single hydrophone measurement at each VSP level. This was recorded while pulling out of hole, and processed once the tool was on surface. Time picking accuracy of the downhole data is ±0.5 ms with the frequency range 6–90Hz, both comparable to Wireline. The repeatability of the hydrophone and geophone time picks was also excellent with the average difference being 0.2 ms and maximum 0.8 ms. High resolution VSP images beneath the well in addition to corridor stacks were derived from the geophone and hydrophone data, showing the geological structure of the reservoir. The quality of the data acquired allowed the client to remove the need for a wireline VSP run; it, therefore, saved significant rig time and costs associated with it, reduced the chances of getting stuck, and significantly reduced the seismic uncertainty.

Gas sampling for mercury analysis

2021 ◽  
Vol 61 (2) ◽  
pp. 559
Author(s):  
Janelle Lawer
Keyword(s):  
Best Practice ◽  
Development Planning ◽  
Project Planning ◽  
Critical Element ◽  
Surface Sampling ◽  
Gas Field ◽  
North West ◽  
Gas Sampling ◽  
The North ◽  
Mercury Analysis

Historically, gas sampling for mercury has been neither accurate nor precise. In some instances, limited understanding of mercury in gas reservoirs has contributed to health, safety and environment (HSE) incidents and project cost escalation. Quality gas sampling for mercury is recognised as a critical element in project planning, best conducted in the exploration and appraisal phases of a field. Early knowledge of mercury concentrations can contribute to the success of development planning, HSE processes and production facility design. Gas Field X on the North West Shelf of Western Australia is in a region of variable mercury-in-gas concentrations. The recent Field X development drilling program commenced with a sampling plan optimised and focussed on mercury analysis using industry best practice operational, logistical and analysis techniques with the intent of building a statistically representative dataset of mercury concentrations. Procedures developed included investigating major sources of scavenging and contamination, innovative pre-job equipment preparation, use of multiple data sources (downhole and surface sampling, offshore and onshore analysis) and blind cross-checking between different laboratories and equipment types. All data has been through rigorous post-analysis quality control. The results of this unprecedented new dataset represent a case study of industry best-practice gas sampling delivering high confidence and repeatable data.

RESERVOIR GEOLOGICAL MODELLING OF THE NORTH RANKIN FIELD, NORTHWEST AUSTRALIA

1986 ◽  
Vol 26 (1) ◽  
pp. 375
Author(s):  
N.B. Beston
Keyword(s):  
Structural Model ◽  
Three Dimensional ◽  
Development Planning ◽  
Lower Jurassic ◽  
Petroleum Engineering ◽  
Seismic Survey ◽  
North West ◽  
The North ◽  
Geological Modelling ◽  
Floodplain Sediments

The North Rankin Field off northwestern Australia provides the major part of the gas reserves for the North West Shelf Project, one of the largest and most ambitious natural resource developments yet undertaken in Australia. Detailed reservoir geological modelling coupled with a three dimensional reservoir simulator have strongly enhanced development planning of the field.The North Rankin structure is a large horst feature of Upper Triassic to Lower Jurassic fluvial and marginal marine sediments unconformably overlain by Cretaceous claystones and marls. The sequence is comprised of braided stream 'sheet like' sandstones, fluvial meandering stream and floodplain sediments, and mixed marginal marine and fluvial channel sandstones.Comprehensive reservoir geological studies involving the examination of reservoir quality, distribution, and continuity were undertaken and combined with an extensive three dimensional seismic survey to provide improved structural definition. The resultant reservoir geological model, which required close interaction and integration of all petroleum engineering disciplines, provided not only the geological basis for improving the estimate of field reserves but also formed the geological input for a reservoir simulation model to optimise the development planning of the North Rankin Field and to predict the reservoir performance of this internally faulted field.The completion of the Domestic Gas Phase of the Project, which involved the drilling of seven development wells, has confirmed the reservoir geological/structural model thus providing a firm basis for the future development planning of the gas recycling and liquefied natural gas phases of the North West Shelf Project.

Worlds First Offshore Horizontal Well Using Jointed Pipe Cemented Frac Sleeve Technology

2022 ◽  
Author(s):  
Shaun Thomson ◽  
Baglan Kiyabayev ◽  
Barry Ritchie ◽  
Jakob Monberg ◽  
Maurits De Heer ◽  
...  
Keyword(s):  
North Sea ◽  
New Technology ◽  
Production Performance ◽  
New Developments ◽  
Coiled Tubing ◽  
The North ◽  
New Novel ◽  
The North Sea ◽  
Reservoir Connectivity ◽  
First Job

Abstract The Valdemar field, located in the Danish sector of the North Sea, targets a Lower Cretaceous, "dirty chalk" reservoir characterized by low permeabilities of <0.5mD, high porosities of >20% and contains up to 25% insoluble fines. To produce economically the reservoir must be stimulated. Typically, this is by means of hydraulic fracturing. A traditional propped fracture consists of 500,000 to 1,000,000 lbs of 20/40 sand, placed using a crosslinked seawater-based borate fluid. The existing wells in the field are completed using the PSI (perforate, isolate, stimulate)1 system. This system was developed in the late 1980s as a way of improving completion times allowing each interval to be perforated, stimulated and isolated in a single trip and has been used extensively in the Danish North Sea in a variety of fields. The system consists of multiset packers with sliding sleeves and typically takes 2-3 days between the start of one fracture to the next. Future developments in this area now require a new, novel and more efficient approach owing to new target reservoir being of a thinner and poorer quality. In order for these new developments to be economical an approach was required to allow for longer wells to be drilled and completed allowing better reservoir connectivity whilst at the same time reducing the completion time, and therefore rig time and overall cost. A project team was put together to develop a system that could be used in an offshore environment that would satisfy the above criteria, allowing wells to be drilled out to 21,000ft and beyond in excess of coiled tubing reach. The technology developed consists of cemented frac sleeves, operated with jointed pipe, allowing multiple zones to be stimulated in one trip, as well as utilizing a modified BHA that allows for the treatments to take place through the tubing, bringing numerous benefits. The following paper details the reasons for developing the new technology, the development process itself, the challenges that had to be overcome and a case history on the execution of the first job of its kind in the North Sea, in which over 7MM lbs of sand was pumped successfully, as well as the post treatment operations which included a proof of concept in utilizing a tractor to manipulate the sleeves. Finally, the production performance will be discussed supported by the use of tracer subs at each of the zones.

ENVIRONMENTAL REVIEW 2000

2001 ◽  
Vol 41 (2) ◽  
pp. 80
Author(s):  
S.J. Smith
Keyword(s):  
Environmental Management ◽  
New Technology ◽  
Petroleum Industry ◽  
South Australia ◽  
Environmental Reporting ◽  
North West ◽  
Natural Gas Pipelines ◽  
The North ◽  
Timor Sea ◽  
Epbc Act

Last year the petroleum industry witnessed the enactment of new legislation both at Commonwealth and State levels. The principal legislative change to environmental management was the introduction of the Commonwealth Government’s Environmental Protection and Biodiversity Act, 2000 (EPBC Act). South Australia and Victoria also implemented new Petroleum Acts and/ or Regulations.Construction of the Eastern Gas Pipeline was also completed last year, whilst preliminary approvals and environmental assessment continues for the Papua New Guinea, Timor Sea and Tasmania Natural Gas pipelines. Offshore exploration continued, particularly in the North West Shelf, Otway Basin, Timor Sea and Bass Strait.Other critical areas of environmental management included greenhouse gases, national pollution inventory reporting and the increasing requirements for environmental approval and management under various state environmental legislation.This paper provides an overview of environmental developments in the petroleum industry during the year 2000, in particular, the implication of new legislation, new technology, e-commerce and a greater focus on environmental reporting.

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.

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