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.

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.

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.

Advances in marine electromagnetic (EM) efficiency with a towed acquisition system

2012 ◽  
Vol 52 (2) ◽  
pp. 699
Author(s):  
Folke Engelmark ◽  
Johan Mattsson ◽  
John Linfoot
Keyword(s):  
Oil And Gas ◽  
Field Tests ◽  
Repeated Sequence ◽  
Dipole Source ◽  
Surface Sampling ◽  
Gas Field ◽  
The North ◽  
Simultaneous Acquisition ◽  
Oil And Gas Field ◽  
Source Signal

A towed marine EM system has been developing since 2004 where both source and receivers are towed behind the same vessel in an arrangement similar to 2D streamer seismic. This is an ideal technology for reducing risk in hydrocarbon targets in general and low saturation gas in particular, as well as the monitoring of CO2 sequestration. The dipole source is 400 or 800 m long and towed at 10 m below the sea surface. The receiver cable is towed at 100 m depth and has receiver offsets between 500 and 8,000 m. A transient source signal is used, allowing deterministic deconvolution of the source signature, which can be of any shape; for example, square wave, PRBS, or optimised repeated sequence (ORS). There are multiple benefits of the towed EM system: Similar in operation to a marine streamer seismic. Improved survey efficiency with source and receivers towed by the same vessel. Real-time monitoring of source and receivers, and quality control of incoming data. Onboard pre-processing. Dense sub-surface sampling. Receivers towed above the seafloor—the influence of strong local anomalies at the seabed is thus minimised. Facilitates simultaneous acquisition of EM and 2D seismic. Successful field tests were conducted in mid-2010 over the Peon gas field and the Troll oil and gas field in the Norwegian sector of the North Sea. A total of 615 line km were acquired during 138 hours, and the data has been successfully processed and inverted to delineate all targets.

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.

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.

scholarly journals 402 - An audit of Lithium Prescribing Practices in an Old Age PsychiatryService highlighting renal impairment in this cohort

2021 ◽  
Vol 33 (S1) ◽  
pp. 29-30
Author(s):  
L. Valentine ◽  
J. Cannon ◽  
S. Marmion ◽  
M. Corcoran ◽  
M. Cryan ◽  
...  
Keyword(s):  
Renal Function ◽  
Renal Impairment ◽  
Old Age ◽  
Best Practice ◽  
Bipolar Affective Disorder ◽  
Prescribing Practices ◽  
Lithium Level ◽  
North West ◽  
The North ◽  
Increased Risk

AbstractAims:To compare Lithium prescribing practices in a Psychiatry of Old Age (POA) Service in the North-West ofIreland among adults aged 65 years and over with best practice guidelines.Methods:Review of the literature informed development of audit standards for Lithium prescribing. These included National Institute for Clinical Excellent (NICE) 2014 guidelines, The British National Formulary(2019) and Maudsley Prescribing Guidelines (2018). Data was collected retrospectively, using an audit-specific data collection tool, from clinical files of POA team caseload, aged 65 years or more and prescribed Lithium over the past year.Results:At the time of audit in February 2020, 18 patients were prescribed lithium, 67% female, average age 74.6 years. Of those prescribed Lithium; 50% (n=9) had depression, 44% (n=8) had bipolar affective disorder (BPAD) and 6% (n=1) schizoaffective disorder.78% (n= 14) of patients met the NICE standard of 3-monthly lithium level. Lithium levels were checkedon average 4.5 times in past year, average lithium level was 0.61mmol/L across the group and 39% (n=7) had lithium level within recommended therapeutic range (0.6-0.8mmol/L).83% of patients (n=15) met the NICE standards of 3 monthly renal tests. Taking into consideration mostrecent blood test results, 100% (n=18) had abnormal renal function.Half (n=9) were initiated on lithium by POA service and of these, 56% (n=5) had documented renal impairment prior to initiation. Of patients on long term lithium at time of referral (n=9), almost half (n=4) had a documented history of lithium toxicity.Conclusions:The results of this audit highlight room for improvement in lithium monitoring of older adults attending POA service. Furthermore, all patients prescribed lithium had impaired renal function. This is an important finding given the associations between those admitted to hospital with COVID-19 and co- morbid kidney disease and increased risk of inpatient death.Our findings highlight the need for three monthly renal function monitoring in elderly prescribed lithiumgiven the additive adverse effects of increasing age and lithium on the kidney. Close working with specialised renal services to provide timely advice on renal management for those with renal impairment prescribed lithium is important to minimise adverse patient outcomes.

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.

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