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.

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.

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.

A NORTH WEST SHELF TRIASSIC REEF PLAY: RESULTS FROM ODP LEG 122

1989 ◽  
Vol 29 (1) ◽  
pp. 328 ◽  
Author(s):  
P.E. Williamson ◽  
N.F. Exon ◽  
B. ul Haq ◽  
U. von Rad
Keyword(s):  
Seismic Reflection ◽  
Upper Triassic ◽  
Seismic Facies ◽  
Late Triassic ◽  
Seismic Reflection Data ◽  
Reef Complex ◽  
North West ◽  
Exmouth Plateau ◽  
The North ◽  
Reflection Data

Site 764 of the Ocean Drilling Program (ODP), drilled during Leg 122 in the Exmouth Plateau region, cored 200 m of Upper Triassic (Rhaetian) reef complex. This site, on the northern Wombat Plateau (northernmost Exmouth Plateau) represents the first discovery of Triassic reefal material near the Australian North West Shelf. Seismic reflection data through Site 764 show that the reef itself corresponds predominantly to a seismically poorly reflective zone. A number of regional unconformities appear to correspond, however, to traceable seismic horizons which pass with reduced amplitude through the reef, indicating stages of reef growth separated by erosion or non- deposition. Seismic facies around the edges of the reef are consistent with the deposition of wedges of prograding reef- derived detritus.Application of the seismic criteria for reef recognition established at ODP Site 764, to other seismic reflection data on the Wombat Plateau, demonstrates that a major Upper Triassic reef complex fringes the margins of the Wombat Plateau. The Wombat Plateau lies at the western end of the North West Shelf, which was part of the southern margin of a warm Tethys Ocean in the Late Triassic, at a palaeolatitude of 25- 30°S. Upper Triassic reefs are known from southeast Indonesia and Papua New Guinea, and now the Wombat Plateau, and may be common elsewhere along the outer margin of the North West Shelf. Upper Triassic reef complexes, with their associated reservoir, source and seal facies, could represent an exciting new petroleum exploration play for the entire North West Shelf. Facies analysis suggests that they are likely only on the outer shelf and slope. Shallow Triassic reef complexes are clearly identifiable using high resolution seismic reflection data. Seismic reflection data of lower resolution may well reveal the associated detrital carbonate wedges, which are more laterally extensive than the reefal core, deeper in the section.

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.

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.

scholarly journals The Waitsia Field, onshore North Perth Basin, Western Australia

2016 ◽  
Vol 56 (1) ◽  
pp. 29 ◽  
Author(s):  
Neil Tupper ◽  
Eric Matthews ◽  
Gareth Cooper ◽  
Andy Furniss ◽  
Tim Hicks ◽  
...  
Keyword(s):  
Flow Characteristics ◽  
Development Planning ◽  
Upper Permian ◽  
Depth Interval ◽  
Lower Permian ◽  
Minimal Processing ◽  
Gas Field ◽  
Full Field ◽  
Field Development ◽  
Primary Porosity

The Waitsia Field represents a new commercial play for the onshore north Perth Basin with potential to deliver substantial reserves and production to the domestic gas market. The discovery was made in 2014 by deepening of the Senecio–3 appraisal well to evaluate secondary reservoir targets. The well successfully delineated the extent of the primary target in the Upper Permian Dongara and Wagina sandstones of the Senecio gas field but also encountered a combination of good-quality and tight gas pay in the underlying Lower Permian Kingia and High Cliff sandstones. The drilling of the Waitsia–1 and Waitsia–2 wells in 2015, and testing of Senecio-3 and Waitsia-1, confirmed the discovery of a large gas field with excellent flow characteristics. Wireline log and pressure data define a gross gas column in excess of 350 m trapped within a low-side fault closure that extends across 50 km2. The occurrence of good-quality reservoir in the depth interval 3,000–3,800 m is diagenetically controlled with clay rims inhibiting quartz cementation and preserving excellent primary porosity. Development planning for Waitsia has commenced with the likelihood of an early production start-up utilising existing wells and gas processing facilities before ramp-up to full-field development. The dry gas will require minimal processing, and access to market is facilitated by the Dampier–Bunbury and Parmelia gas pipelines that pass directly above the field. The Waitsia Field is believed to be the largest conventional Australian onshore discovery for more than 30 years and provides impetus and incentive for continued exploration in mature and frontier basins. The presence of good-quality reservoir and effective fault seal was unexpected and emphasise the need to consider multiple geological scenarios and to test unorthodox ideas with the drill bit.

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.

SUB-SURFACE UNCERTAINTY IN OIL FIELDS: LEARNINGS FROM EARLY PRODUCTION OF LEGENDRE OIL FIELDS

2003 ◽  
Vol 43 (1) ◽  
pp. 401
Author(s):  
R. Seggie ◽  
F. Jamal ◽  
A. Jones ◽  
M. Lennane ◽  
G. McFadzean ◽  
...  
Keyword(s):  
Planning Process ◽  
Development Planning ◽  
Oil Field ◽  
Production Performance ◽  
Oil Fields ◽  
High Rate ◽  
Secondary Development ◽  
North West ◽  
Field Development ◽  
Small Primary

The Legendre North and South Oil Fields (together referred to as the field) have been producing since May 2001 from high rate horizontal wells and had produced 18 MMBBL by end 2002. This represents about 45% of the proven and probable reserves for the field.Many pre-drill uncertainties remain. The exploration and development wells are located primarily along the crest of the structure, leaving significant gross rock volume uncertainty on the flanks of the field. Qualitative use of amplitudes provides some insight into the Legendre North Field but not the Legendre South Field where the imaging is poor. The development wells were drilled horizontally and did not intersect any fluid contacts.Early field life has brought some surprises, despite a rigorous assessment of uncertainty during the field development planning process. Higher than expected gas-oil ratios suggested a saturated oil with small primary gas caps, rather than the predicted under-saturated oil. Due to the larger than expected gas volumes, the gas reinjection system proved to have inadequate redundancy resulting in constrained production from the field. The pre-drill geological model has required significant changes to reflect the drilling and production results to date. The intra-field shales needed to be areally much smaller than predicted to explain well intersections and production performance. This is consistent with outcrop analogues.Surprises are common when an oil field is first developed and often continue to arise during secondary development phases. Learnings, in the context of subsurface uncertainty, from other oil fields in the greater North West Shelf are compared briefly to highlight the importance of managing uncertainty during field development planning. It is important to have design flexibility to enable facility adjustments to be made easily, early in field life.

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