Decommissioning of Australia's oil and gas facilities in the 21st century

2017 ◽  
Vol 57 (2) ◽  
pp. 397
Author(s):  
Stuart Barrymore
Keyword(s):  
21St Century ◽  
Western Australia ◽  
Oil And Gas ◽  
The State ◽  
Asia Pacific ◽  
Reform Process ◽  
Discussion Paper ◽  
Legislative Reform

Through 2016, there has been increasing interest in the rules and regulations that apply to decommission facilities in Australia’s offshore waters. APPEA is developing guidelines as is the State of Western Australia. The Department of Industry Innovation and Research is preparing a discussion paper on Australia’s decommissioning laws, regulation and practice. It is expected to issue by the end of 2016. These developments are long overdue. Australia’s laws regarding these activities have barely changed since the offshore legislation was enacted in 1967. How major facilities are decommissioned in Australia will be a matter of interest to numerous stakeholders. It seems likely that decisions taken in the next two years will result in a modernisation of Australia’s law and practice and will determine how the major offshore facilities will be decommissioned over the next 30 years. The paper canvasses the reform process, considers the more modern regimes overseas and whether they have achieved their objectives, looks at regional (Asia–Pacific) practice and informs delegates as to the path forward on any legislative reform. The position of the States and the Commonwealth are contrasted.

OIL AND GAS INDUSTRY IN WESTERN AUSTRALIA

1999 ◽  
Vol 39 (1) ◽  
pp. 30
Author(s):  
M. Meaton
Keyword(s):  
Western Australia ◽  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Gas Production ◽  
The State ◽  
Full Potential ◽  
Gas Industry ◽  
Oil And Gas Production ◽  
Advantages And Disadvantages ◽  
Petroleum Companies

The oil and gas production sector in Western Australia has grown dramatically in recent years and now represents the largest resource sector in the State economy. The industry has a very promising future but it faces a number of challenges if it is to achieve its full potential. Its production location in remote parts of the State confers both advantages and disadvantages. Chief among the disadvantages is the challenge of convincing the community and government of the benefits from the industry when many of those benefits are not apparent to the majority of the population. The emphasis in this paper is on economic impacts, social benefits and community attitudes.WA has produced about 820 million barrels of oil and 2000 million barrels of natural gas when gas is calculated in energy equivalent terms. Petroleum energy production has increased dramatically over the last 15 years and the State is now a substantial energy exporter. Petroleum sources provide the energy for over 85% of the final energy used in the State. Total industry investment over the last 18 years has been nearly $21,000 million for an average of $3.2 million each day. Direct employment by petroleum companies is around 2,500 people with flow-on employment in the services sector estimated at over 17,000 people. Petroleum companies have been major contributors to government revenue and to the development of remote regions in WA.

Collaboration and Optimization Processes Contribute to Ultra-ERD Offshore Well Success

2021 ◽  
Vol 73 (05) ◽  
pp. 61-62
Author(s):  
Judy Feder
Keyword(s):  
Western Australia ◽  
Oil And Gas ◽  
New Technology ◽  
Data Interpretation ◽  
Primary Objective ◽  
Asia Pacific ◽  
Time Data ◽  
The North ◽  
Engineering Collaboration ◽  
Engineering Designs

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 202251, “Transforming the Mindset To Drill Ultra-ERD Wells With High Tortuosity,” by Barry Goodin, SPE, Duane Selman, and Andy Wroth, Vermilion Oil and Gas, 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. The complete paper describes the extensive integrated engineering collaboration and optimization process that allowed an operator to push the drilling and completion envelope to drill a pair of complex, ultra-extended-reach-drilling (ERD) wells in the mature Wandoo field in the Carnarvon Basin offshore Western Australia. The shallow reservoir depth, extreme ERD profile, and high tortuosity requirement for the wells posed significant challenges. These were overcome with extensive planning; integrated engineering designs; application of new technology; good-quality, real-time data interpretation; and strong execution support from both rig site and town. Introduction The Wandoo field, in 56 m of water off-shore Western Australia, was discovered in 1991 and subsequently developed and placed on production in 1993. The shallow unconsolidated sandstone reservoir consists of a heavily biodegraded oil column overlain by a gas cap and supported by a strong aquifer drive. Field infrastructure consists of a 15-well-slot manned production facility, Wandoo B, and a five-slot monopod, Wandoo A, which is tied back to Wandoo B by subsea in-field pipelines. In late 2018, the operator planned and executed a two-well drilling campaign consisting of two complex, ultra-ERD wells, Wandoo B15 and B16. Both wells were planned to be batch drilled for the top hole and intermediate hole sections, with the production hole sections to be drilled and completed sequentially. The primary objective for the B15 well was to recover unswept oil along the western flank of the field and track the well along the main Wandoo fault to the north to assess the structure and reserves from the northern tip of the field. The B16 well objective was to access unswept reserves through the center and down to the south of the field, essentially twinning the B11ST1 well, another ERD well drilled on an earlier campaign, to its eastern flank. To maximize recovery, both wells needed to be placed approximately 1 m below the top of the reservoir, except where overlain by the gas cap, in which case the wells were to be placed approximately 2 m below the gas/oil contact to avoid gas coning. Drilling Challenges and Solutions The first half of the complete paper presents a detailed discussion of the drilling challenges and solutions, illustrated with schematics, maps, charts, and graphs. Both Wells B15 and B16 were classified as ultra-ERD wells because the shallow true vertical depth (TVD) of the reservoir resulted in extreme stepout ratios and required highly complex well paths to access the remaining reserves. The complete paper lists various specific drilling- and systems-related challenges.

New Monoethylene-Glycol Sensor Validated by Flow Loop Under Hydrate-Forming Conditions

2021 ◽  
Vol 73 (08) ◽  
pp. 49-50
Author(s):  
Chris Carpenter
Keyword(s):  
Western Australia ◽  
Test Section ◽  
Oil And Gas ◽  
Complex Geometry ◽  
Hydrate Formation ◽  
Pilot Scale ◽  
Asia Pacific ◽  
Flow Loop ◽  
The University ◽  
Monoethylene Glycol

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202375, “Validation of a Novel MEG Sensor Employing a Pilot-Scale Subsea Jumper,” by Asheesh Kumar, The University of Western Australia; Mauricio Di Lorenzo, SPE, CSIRO Energy; and Bruce W.E. Norris, SPE, The University of Western Australia, 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. Online pipeline-management systems provide real-time and look-ahead functionality for production networks. They are limited, however, by a dearth of data with which to inform their predictions. This represents a barrier to a true, high-fidelity digital twin. Greater integration with new sensor technologies is needed to bound model predictions and improve their reliability. In this work, the authors present a novel monoethylene-glycol (MEG) sensing system and validate it in a specially constructed flow loop. Introduction Subsea jumpers experience a high probability of hydrate blockages. The most common practice used to avoid hydrate formation in subsea wellhead jumpers essentially is based on the injection of thermodynamic hydrate inhibitors such as MEG and methanol at high flow rates to flush out and inhibit the water pooled in the low spots of the jumper spools. Such hydrate management operations in deep water require adequate planning to minimize unproductive time and may not be feasible in unplanned well shutdowns. To improve the models implemented in current sensing technologies and explore their potential for new functionalities to detect hydrate formation, measurements under realistic field conditions in a controlled environment are vital. In this work, a flow loop that replicates the geometry of industrial subsea jumpers was deployed to investigate the performance of a new MEG sensor for subsea applications under hydrate-forming conditions. Preliminary baseline experiments were performed at steady state and during gas-restart operations in the absence of any hydrates in the jumper flow loop. Experiments were performed at 64.4°F with nitrogen (N2) gas at 1,200 psig and superficial gas velocity ranges from 0.82 to 2.88 ft/s. The MEG-sensing system’s performance was investigated under hydrate-forming conditions with and without MEG (10–30 wt% in water) in the jumper test section. These experiments were performed at temperatures ranging from 25.2 to 35.6°F. Experimental Flow Loop The flow loop consists of a test section connected to independent gas and liquid injection equipment at the inlet and gas-separation facilities at the outlet, which allows for continuous recirculation of gas and a once-through pass of the liquid. The test section has a complex geometry, with three identical low points (LPs) and two high points. The horizontal length of each low and high points is 12 ft, 10 in., and 7 ft, 7 in., respectively, and total height is 13 ft, 2 in. The test section is equipped with 12 pressure and temperature sensors distributed at regular intervals, a MEG sensor at the second LP, a throttling valve downstream of the first high point to mimic a wellhead choke, and a viewing window at the outlet.

Varied Responses to Human-Induced Seismicity in the City of Azle, Texas

2019 ◽  
Vol 3 (1) ◽  
pp. 1-8
Author(s):  
Sarmistha R. Majumdar
Keyword(s):  
State Government ◽  
Induced Seismicity ◽  
Oil And Gas ◽  
The United States ◽  
The State ◽  
Prior History ◽  
Small Community ◽  
Regulatory Policies ◽  
The Status

Fracking has helped to usher in an era of energy abundance in the United States. This advanced drilling procedure has helped the nation to attain the status of the largest producer of crude oil and natural gas in the world, but some of its negative externalities, such as human-induced seismicity, can no longer be ignored. The occurrence of earthquakes in communities located at proximity to disposal wells with no prior history of seismicity has shocked residents and have caused damages to properties. It has evoked individuals’ resentment against the practice of injection of fracking’s wastewater under pressure into underground disposal wells. Though the oil and gas companies have denied the existence of a link between such a practice and earthquakes and the local and state governments have delayed their responses to the unforeseen seismic events, the issue has gained in prominence among researchers, affected community residents, and the media. This case study has offered a glimpse into the varied responses of stakeholders to human-induced seismicity in a small city in the state of Texas. It is evident from this case study that although individuals’ complaints and protests from a small community may not be successful in bringing about statewide changes in regulatory policies on disposal of fracking’s wastewater, they can add to the public pressure on the state government to do something to address the problem in a state that supports fracking.

Minerals as an object of accounting and economic security of the oil and gas company implementing the production sharing agreement

2020 ◽  
Vol 23 (11) ◽  
pp. 1291-1312
Author(s):  
N.V. Zyleva
Keyword(s):  
Oil And Gas ◽  
Economic Security ◽  
The State ◽  
Professional Judgment ◽  
Production Sharing ◽  
Security Service ◽  
Geological Information ◽  
Oil And Gas Companies ◽  
Mineral Reserves ◽  
Economic Risks

Subject. This article discusses the practice of ensuring the economic security of oil and gas companies operating under the terms of production sharing agreements, where minerals are the object of security. Objectives. The article aims to justify the need to apply professional judgment in the organization of reliable accounting of minerals, explored and extracted under the terms of the production sharing agreement implementation, to avoid various risks to the entity's economic security. Methods. For the study, I used the methods of deduction and modeling. Results. The article presents proposals to arrange accounting of intangible exploration assets (geological information on mineral reserves) and finished products (the part of the extracted minerals owned by the investor and the part owned by the State). Conclusions. As strategic minerals, oil and gas are the targets of various economic risks. Professionals familiar with the specifics of accounting operations in the implementation of the production sharing agreement should be prepared to prevent these risks. The results obtained can be used to design accounting policies and develop local regulations on the tasks and functions of the economic security service of the organization implementing the production sharing agreement.

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