Early Production Life of Wheatstone Project Offshore Australia Yields Key Lessons

2021 ◽  
Vol 73 (08) ◽  
pp. 51-52
Author(s):  
Chris Carpenter
Keyword(s):  
Oil And Gas ◽  
Asia Pacific ◽  
North West ◽  
The North ◽  
Sand Control ◽  
Single Well ◽  
Early Production ◽  
Northern Carnarvon Basin ◽  
Shelf Region ◽  
Gas Fields

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202246, “Wheatstone: What We Have Learned in Early Production Life,” by John Pescod, SPE, Paul Connell, SPE, and Zhi Xia, Chevron, et al., prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. Wheatstone and Iago gas fields, part of the larger Wheatstone project, commenced production in June 2017. The foundation subsea system includes nine Wheatstone and Iago development wells tied back to a central Wheatstone platform (WP) for processing. Hydrocarbons then flow through an export pipeline to an onshore processing facility that includes two liquefied-natural-gas (LNG) trains and a domestic gas facility. The complete paper highlights some of the key learnings in well and reservoir surveillance analysis and optimization (SA&O) developed using data from early production. Asset Overview Chevron Australia’s Wheatstone project is in the North West Shelf region offshore Australia (Fig. 1). Two gas fields, Wheatstone and Iago (along with a field operated by a different company), currently tie into the WP in the Northern Carnarvon Basin. These two gas fields are in water depths between 150 and 400 m. The platform processes gas and condensate through dehydration and compression facilities before export by a 220-km, 44-in., trunkline to two 4.45-million-tonnes/year LNG trains and a 200 tera-joule/day domestic gas plant. A Wheatstone/Iago subsea system consisting of two main corridors delivers production from north and south of the Wheatstone and Iago fields to the WP. Currently, the subsea system consists of nine subsea foundation development wells, three subsea production manifolds, two subsea 24-in. production flowlines, and two subsea 14-in. utility lines. The nine foundation development wells feed the subsea manifolds at rates of up to 250 MMscf/D. These wells have openhole gravel-pack completions for active sand control and permanent downhole gauges situated approximately 1000-m true vertical depth above the top porosity of multi-Darcy reservoir intervals for pressure and temperature monitoring. All wells deviate between 45 and 60° through the reservoir with stepout lengths of up to 2.5 km. The two subsea 24-in. production flowlines carry production fluids from the subsea manifolds to two separation trains on the WP. Each platform inlet production separator can handle up to 800 MMscf/D. The two 14-in. utility flowlines installed to the subsea manifolds allow routing of a single well to the platform multiuse header, which can direct flow into the multiuse separator (MUS) or other production separators at a rate of 250 MMscf/D.

PREPARATION AND IMPLEMENTATION OF A SAFETY MANAGEMENT SYSTEM IN BHPP

1997 ◽  
Vol 37 (1) ◽  
pp. 657
Author(s):  
P.C. Hunter
Keyword(s):  
Management System ◽  
Oil And Gas ◽  
Safety Management ◽  
Oil Field ◽  
Safety Performance ◽  
Asia Pacific ◽  
Gas Treatment ◽  
Safety Management System ◽  
North West ◽  
The North

BHP is a leading global resources company which comprises four main business groups: BHP Copper, BHP Minerals, BHP Steel and BHP Petroleum. BHP Petroleum (BHPP) global operations are divided into four Regions and Australia/Asia Region is responsible for exploration, production, field development and joint ventures in the Asia-Pacific region. In Australia, the Company's largest producing assets are its shares of the Gippsland oil and gas fields in Bass Strait and the North West Shelf project in Western Australia.BHPP operates three Floating Production, Storage and Offloading (FPSO) vessels-Jabiru Venture, Challis Venture and Skua Venture-in the Timor Sea and one FPSO, the Griffin Venture, in the Southern Carnarvon Basin. Stabilised oil is offloaded from all four FPSOs by means of a floating hose to a shuttle tanker. Gas from the Griffin Venture is compressed and transferred through a submarine pipeline to an onshore gas treatment plant.BHPP's Asian production comes from the Dai Hung oil field offshore Vietnam where BHPP is the operator and from Kutubu in Papua New Guinea.In Melbourne, BHPP operates a Methanol Research Plant and produced Australia's first commercial quantities of methanol in October 1994.BHPP is an extremely active offshore oil and gas explorer and has interests in a number of permits and blocks in the Australian-Indonesian Zone of Co-operation.This paper discusses BHPP's approach to safety management, both for its worldwide operations and specifically in Australia/Asia Region. It explains how BHPP's worldwide safety management model takes regional regulatory variations into account. It shows, specifically, how this has been done in Australia/Asia Region using what BHPP considers to be a best practice approach.The paper describes how BHPP Australia/Asia Region benchmarked its performance against other operators in Australia and the North Sea. It explains how the findings of the benchmarking study were used to plan the preparation of a safety management system (SMS). The structure of the SMS is described along with the legal requirements in Australia.The paper concludes that implementation of the SMS is progressing according to plan and points out that safety cases for the FPSOs have been submitted to the Regulators. Implementation of the SMS and the drive for world class safety standards is having a substantial effect and safety performance is improving. One measure of safety performance, the Lost Time Injury Frequency Rate (LTIFR) is down from around 15 at the end of 1994 to under 3 in December 1996.

2010 environmental update

2011 ◽  
Vol 51 (1) ◽  
pp. 179
Author(s):  
Alastair Sharp-Paul ◽  
Alexandra Hare ◽  
Alice Turnbull ◽  
Tara Halliday
Keyword(s):  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Environmental Research ◽  
Gas Industry ◽  
North West ◽  
The North ◽  
The Usa ◽  
Policy And Suggestion ◽  
High Level ◽  
Gas Fields

Focusing on Australian projects, this paper provides a summary of the key environmental challenges and developments that arose in 2010 and the industry’s response. The paper considers: developments in legislation and the regulatory environment relating to environmental approvals and management; major project approvals and their environmental requirements and implications; key environmental incidents; and reviews new environmental research and management initiatives that were introduced by the industry. A number of states have introduced changes to the way legislation and regulations are interpreted through changes to guidelines and administrative procedures. There has been a general increase in the standard and level of information that regulators expect proponents to provide and while generally these expectations are documented in guidelines and other documents, in some instances there has been a perceived ‘moving of the goal posts’ without clear guidance on what is expected and how the information will be considered once provided. There has been a number of major projects either commencing or gaining environmental approval in 2010. This includes major projects: in Western Australia, on the North West Shelf and in the Timor Sea/Browse Basin; onshore in Queensland in the coal-seam gas fields and continued exploration and development both onshore and offshore around Australia. One of the most significant approvals in 2010 was the Prelude LNG Project–the first approval in Australia of floating LNG technology. Major environmental incidents in 2009 (Montara in Australia and Macondo in the USA) continued to have repercussions in 2010 with the draft government response to the Report of the Montara Commission of Inquiry released in November. These incidents have put the oil and gas industry under the spotlight and this paper looks at some of the statistics on the frequency and severity of environmental incidents, albeit at a high level. Finally, the industry has continued to implement a number of environmentally related initiatives both in response to government policy and suggestion and independently through groups such as the APPEA environment committee.

Integration of new interpretation, attribute analysis and inversion results for the Dampier Sub-basin, North West Shelf of Australia

2021 ◽  
Vol 61 (2) ◽  
pp. 611
Author(s):  
Jarrad Grahame ◽  
Jianfeng Yao
Keyword(s):  
Oil And Gas ◽  
New Ventures ◽  
Large Area ◽  
North West ◽  
The North ◽  
Avo Inversion ◽  
Attribute Analysis ◽  
New Interpretation ◽  
Northern Carnarvon Basin ◽  
Carnarvon Basin

The Davros-Typhon Multi-Client 3D surveys are located approximately 70km from the north-west coast of Australia, largely covering the NE trending Dampier Sub-basin and straddling the Rankin Trend within the Northern Carnarvon Basin. The basins within the North West Shelf formed as a result of seafloor spreading, associated with the breakup of the North West margin of East Gondwana. The combined, contiguous Davros-Typhon survey areas cover a number of significant discoveries and producing fields, which include both oil and gas accumulations. The key objective of the survey was to enhance the imaging of Triassic to Lower Cretaceous reservoir units and to develop a new interpretation framework, made possible by the modern broadband acquisition parameters and advanced processing techniques. Challenges associated with imaging and interpretation include the effects of high velocity carbonate overburden, steeply dipping structures, fault shadow and structural complexity at depth, which is critical for evaluation of reservoir targets. A major reprocessing effort was undertaken to further mitigate these issues, which included Davros and a number of adjacent existing 3D surveys, resulting in the Typhon Multi-Client 3D. CGG Multi-client and New Ventures geoscientists, in collaboration with CGG Seismic Imaging, have undertaken new interpretation and amplitude versus offset (AVO) inversion analysis using subsets of the Typhon 3D. The resulting volume-based attribute analysis and integration of new AVO inversion results demonstrates enhanced attribute quality for the reprocessed data and provides a platform for quantitative analysis over a large area of the Northern Carnarvon Basin.

2013 PESA production and development review

2014 ◽  
Vol 54 (1) ◽  
pp. 451
Author(s):  
Geoff O'Brien ◽  
Monica Campi ◽  
Graeme Bethune
Keyword(s):  
Oil And Gas ◽  
Oil Production ◽  
Gas Production ◽  
Oil And Gas Development ◽  
Oil And Gas Production ◽  
North West ◽  
The North ◽  
Western Flank ◽  
Under Construction ◽  
Gas Fields

The boom in Australian oil and gas development continued in 2013, with record overall investment of $60 billion. This investment resulted from spending on the seven LNG projects under development, together with that on numerous other oil and gas developments. These projects are expected to collectively contribute up to 665 million barrels of oil equivalent (MMboe) to Australia’s oil and gas production, which totaled 513.8 MMboe in 2013. LNG, presently Australia’s seventh largest export, is likely to soon rival the nation’s largest export, iron ore. By the end of 2013, three of the LNG projects under construction—Gorgon, Queensland Curtis LNG (QCLNG) and Gladstone LNG (GLNG)—were more than 70% complete; first LNG will be before the end of 2014 for QCLNG and in 2015 for Gorgon, GLNG and Australia Pacific LNG (APLNG). The other three LNG projects—Wheatstone, Prelude and Ichthys—are close behind. These new LNG projects follow Pluto, Australia’s third LNG project, which commenced production in 2012. A full year of production from Pluto drove increased gas production in 2013. Woodside also completed the North Rankin redevelopment and continued development of the Greater Western Flank, both of which will extend the life of the North West Shelf (NWS) project. A number of other projects also commenced production. In the Carnarvon Basin, oil production began at Santos’s Fletcher-Finucane Field, and at BHP Billiton’s Macedon project, domestic gas production started. In the Timor Sea, PTTEP’s Montara Field began production of oil. In Victoria, the ExxonMobil Kipper-Turrum-Tuna project came online, with the production of gas from Tuna and oil from Turrum. Production of gas from Origin Energy’s Geographe Field (as part of the Otway Gas Project) commenced in mid-2013. Onshore oil production grew in 2013, with the Cooper-Eromanga Basin now producing more oil than any other onshore Australian basin. A major effort is underway to increase production from the western flank oil trend and to develop both the conventional and unconventional gas fields in the Cooper Basin. Spending on the development of new projects probably peaked in 2013 and there is growing concern about a dearth of future projects, with expansion of existing LNG projects and development of new projects being pushed back due to a combination of increased costs and growing international competition. There are also ongoing industry concerns about impediments to onshore gas exploration and development generally.

Geothermal condition and outlook for oil and gas deposits in the north-west Black Sea shelf

2002 ◽  
Vol 8 (2-3) ◽  
pp. 206-208
Author(s):  
V.G. Osadchyi ◽  
◽  
O.A. Prykhod'ko ◽  
I.I. Hrytsyk ◽  
◽  
...  
Keyword(s):  
Black Sea ◽  
Oil And Gas ◽  
North West ◽  
The North ◽  
West Black Sea

scholarly journals A robust fuzzy logic-based model for predicting the critical total drawdown in sand production in oil and gas wells

PLoS ONE ◽  
2021 ◽  
Vol 16 (4) ◽  
pp. e0250466
Author(s):  
Fahd Saeed Alakbari ◽  
Mysara Eissa Mohyaldinn ◽  
Mohammed Abdalla Ayoub ◽  
Ali Samer Muhsan ◽  
Ibnelwaleed A. Hussein
Keyword(s):  
Fuzzy Logic ◽  
Correlation Coefficient ◽  
Oil And Gas ◽  
Maximum Error ◽  
Physical Parameters ◽  
Sand Production ◽  
Gas Reservoirs ◽  
The North ◽  
Sand Control ◽  
North Adriatic Sea

Sand management is essential for enhancing the production in oil and gas reservoirs. The critical total drawdown (CTD) is used as a reliable indicator of the onset of sand production; hence, its accurate prediction is very important. There are many published CTD prediction correlations in literature. However, the accuracy of most of these models is questionable. Therefore, further improvement in CTD prediction is needed for more effective and successful sand control. This article presents a robust and accurate fuzzy logic (FL) model for predicting the CTD. Literature on 23 wells of the North Adriatic Sea was used to develop the model. The used data were split into 70% training sets and 30% testing sets. Trend analysis was conducted to verify that the developed model follows the correct physical behavior trends of the input parameters. Some statistical analyses were performed to check the model’s reliability and accuracy as compared to the published correlations. The results demonstrated that the proposed FL model substantially outperforms the current published correlations and shows higher prediction accuracy. These results were verified using the highest correlation coefficient, the lowest average absolute percent relative error (AAPRE), the lowest maximum error (max. AAPRE), the lowest standard deviation (SD), and the lowest root mean square error (RMSE). Results showed that the lowest AAPRE is 8.6%, whereas the highest correlation coefficient is 0.9947. These values of AAPRE (<10%) indicate that the FL model could predicts the CTD more accurately than other published models (>20% AAPRE). Moreover, further analysis indicated the robustness of the FL model, because it follows the trends of all physical parameters affecting the CTD.

Pioneering Li-ion batteries on an offshore platform

2018 ◽  
Vol 58 (2) ◽  
pp. 719
Author(s):  
Lourens Jacobs ◽  
Nancy Nguyen ◽  
Ryan Beccarelli
Keyword(s):  
Power Generation ◽  
Gas Turbine ◽  
Oil And Gas ◽  
Generation System ◽  
Spinning Reserve ◽  
Fuel Gas ◽  
North West ◽  
The North ◽  
Li Ion ◽  
Power Generation System

Woodside is an Australian oil and gas company and a leading global operator of offshore gas platforms and onshore LNG processing facilities. It is a public company listed on the Australian Securities Exchange headquartered in Perth, Western Australia. Woodside operates the Goodwyn A gas platform on behalf of the North West Shelf (NWS) Project. Woodside assessed Li-ion battery technology and considered the technology mature and ready to be utilised on offshore and onshore operating assets. Woodside operates dedicated islanded gas turbine power generation at each of its onshore and offshore facilities. It was concluded that a large battery energy storage solution (BESS) can deliver several advantages if connected to such an islanded power generation system. The most significant benefit materialises by using a BESS as backup (or spinning reserve) for the gas turbine generators (GTGs). Woodside decided to pioneer the Li-ion BESS technology in a first of its kind application on the NWS Project offshore Goodwyn A gas platform. The Goodwyn A BESS is designed for a 1 MW power and 1 MWh energy capacity, which is considered sufficient to provide the spinning reserve for the Goodwyn A platform. Currently, Goodwyn A operates four 3.2 MW GTGs to provide a typical load of 7–8 MW, with one GTG providing the N+1 spinning reserve. When the BESS is connected to the power generation system, Goodwyn A will operate three GTGs, with the BESS proving the backup in case one of the GTGs trip. The BESS will provide the full 1 MW for a minimum of 1 h, which will give the operators enough time to start the standby GTG or adjust the facility loads (load shedding). The result will be a decrease in overall fuel gas consumption (due to better efficiencies on the remaining GTGs in operation) and a related reduction in CO2 emissions. The project supports the overall objective of the North West Shelf Project to improve the energy intensity of its facilities by 5% by 2020. Woodside believes that developing capability and experience on the installation of BESSs, using Goodwyn A as an early adopter, will facilitate similar and larger installations on other Woodside operated offshore and onshore assets. This is one of the technologies Woodside believes will play an important role to ensure a lower carbon future globally.

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