LAKE MARGARET FEASIBILITY STUDY
VOLUME 1: MAIN REPORT
Prepared by: HYDRO ELECTRIC CORPORATION ARBN 072 377 158 ABN 48 072 377 158 4 Elizabeth Street, Hobart Tasmania, Australia
Lake Margaret Feasibility Study
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EXECUTIVE SUMMARY
Introduction and background
The Lake Margaret Power Scheme, which began producing electricity in 1914, is one of the oldest hydropower schemes in Australia and is an area of outstanding heritage significance. It is an example of the pioneering period of hydro-electric development in Australia. Due principally to its private ownership and continuous operation for most of its life, the site has retained nearly all of its early infrastructure and equipment.
The scheme consists of the following major assets:
• Lake Margaret Dam (post tensioned concrete gravity dam).
• King Billy pine woodstave pipeline, transporting water from the dam to the penstock.
• Penstock.
• Upper power station.
• Lower power station, (decommissioned in 1994).
• Lake Margaret Village, including seven cottages and a community hall.
The site has been provisionally listed on the Tasmanian Heritage Register (THR) and is currently being assessed for National Heritage Listing. The provisional listing on the THR holds the same legislative requirement as a full listing, which means any redevelopment would require approval from the Tasmanian Heritage Council.
Hydro Tasmania took over ownership of the scheme in 1985 from the Mt Lyell Mining and Railway Company and, until its closure in June 2006, the scheme produced approximately 0.5% of Tasmania’s total electricity output.
The aging power station was closed on 30 June 2006, primarily due to safety concerns regarding the woodstave hilltop pipeline, which had been assessed as being at end of life and at risk of failure.
Hydro Tasmania has commissioned this feasibility study to determine the best long-term strategy for utilising the energy potential of Lake Margaret with consideration to economic, heritage, environmental and social implications of the options available.
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Preparation of this study has included the development of concept designs by Hydro Tasmania, review of those designs by Snowy Mountains Engineering Corporation (SMEC), and preparation of construction cost estimates and risk review by independent engineering consultants, Johnstone McGee and Gandy (JMG), with inputs from suppliers of steel, timber and fibreglass pipelines and suppliers of hydro-electric turbine/generator sets. International woodstave pipeline experts were also engaged to review the existing pipeline condition and provide estimates of replacement pipeline costs.
This study has focussed only on redevelopment options for the upper station. Hydro Tasmania intends to review potential opportunities for the lower station in the context of the redevelopment option implemented for the upper station.
Preferred options
Hydro Tasmania has investigated a number of options for redevelopment of the Lake Margaret Power Scheme. Emerging from this current re-evaluation, the two economically favoured options are:
1. Minimalist refurbishment of the existing power station.
2. Construction of a new power station with a single generator adjacent to the existing power station.
A new hilltop pipeline would be required for both these options.
Both options are considered marginally viable.
Implementation of either option would need a detailed Heritage Impact Assessment and approval from the Tasmanian Heritage Council. However, both can be designed to minimise impact on heritage value.
Table 1 identifies likely up-front construction costs for both options and the expected range of internal rate of return (IRR). The rate of return is influenced by operation and maintenance costs, energy prices and prices for Renewable Energy Certificates.
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Table 1 Economics of favoured options
Upfront IRR Assessed capital cost 80% Option range range confidence % $M IRR 1. Minimalist refurbishment 11-13 6-13 9.5% of existing power station 2. New power station approx 17-20 7-13 11% 10 MW
The following table identifies other factors that could influence the preferred option:
Table 2 Rationale for refurbishment versus new power station
Option 1. • Lower capital cost; lower equity requirements Refurbishment • Less time, expense, and uncertainty with heritage and development Pros approval matters • Earlier completion • Lower up-front capital cost. Option 2. • Higher NPV New Power • More renewable energy generated Station Pros • More certainty on future O&M costs • Easier to manage the safety risk with new equipment.
Condition of current woodstave hilltop pipeline
Hydro Tasmania closed the Lake Margaret Power Station primarily due to safety concerns regarding the woodstave hilltop pipeline, which had been assessed as being at end of life and at risk of failure.
As part of this study, Hydro Tasmania commissioned Sinclair Knight Merz (SKM) to provide a report on the condition of the existing woodstave pipe. SKM concluded that the existing pipeline had reached the end of its useful life and, therefore, continued operation of the scheme was, at a minimum, reliant on a replacement pipeline.
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In view of this analysis, Hydro Tasmania engaged Canadian woodstave pipe and barrel manufacturer, Canbar, to provide a report on the current woodstave pipeline and provide advice on construction of a replacement pipe. Canbar also concluded that the current pipe has reached the end of its life and should be decommissioned.
A report was also commissioned on the specific condition of the timber in the woodstave pipeline. This study, by Acutel Consulting, included sampling and analysis of over 222 core samples. This report indicated that timber thickness and quality has deteriorated significantly, particularly in the top half of the pipe. Average thickness in the top half is now 29.6 mm with 33.4 mm in the bottom half compared to an original thickness of 48 mm. Although significant amounts of timber have deteriorated to the extent that any service life is problematic, there appears to be a salvageable quantity of King Billy pine that could be recycled for use as craft wood or other alternatives.
Hydro Tasmania conducted a detailed condition assessment of the woodstave foundations and supports and concluded that the foundations are generally in poor condition. It is considered the existing foundations would be of little value as part of any replacement pipe construction.
Woodstave pipeline replacement
Given the condition analyses of the woodstave pipeline noted above, any redevelopment option would require a replacement of the current woodstave pipeline.
Options considered for replacing the current woodstave pipe include steel, glass reinforced plastic (GRP) and woodstave. Investigations into these options highlighted the following key points.
• In terms of durability and reliability, steel is considered to be the best option with an 80 year design life.
• A replacement woodstave pipeline is considered to be higher risk than steel due to fire risk, and potentially less predictable service life.
• Timber is still a suitable material and could be considered if the price is competitive with steel. The lowest budget price obtained for a new woodstave is comparable to both steel and GRP, but dependent on firm tender prices.
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• The lowest price obtained for timber not requiring treatment was based on North American supplied Yellow Cedar, which is used in North America in pipe and barrel applications.
• Consideration has been given to the use of King Billy pine and enquiries have been made with Forestry Tasmania, but, due to limited quantities and price, it is not considered a viable option.
• GRP is considered to be the highest risk option with a 30 year design life and susceptibility to mechanical damage and fire risk.
A replacement woodstave is likely to be considered as a favourable heritage outcome although steel and GRP are appropriate if considered in the context of keeping the scheme running and preserving other heritage values.
The most practical alignment would be to use the approximate 1938 alignment, between the hilltop valve and the existing crossover of pipeline and tramway, and the original 1914 alignment between the existing crossover and the dam. This would allow for a straighter and shorter alignment reducing construction costs and pipeline losses during operation. The alignment would avoid the proposed locations for the preserved sections. A walking track would still be provided to the dam.
Preservation of pipeline sections
Hydro Tasmania proposes to retain three sections of the current woodstave pipe for heritage interpretation. This cost has been included in the estimates. It is expected that, once the water is drained from the pipeline, collapse of the timber staves will occur. However, it is uncertain as to when this would happen. Internal supports will be incorporated to stabilise the sections proposed to be retained for heritage interpretation.
Detailed design will be subject to a Heritage Impact Assessment and will need approval from the Tasmanian Heritage Council.
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Occupational health and safety considerations
It is proposed for OH&S reasons to construct the new hilltop pipeline using a permanently installed steel rail track and trolley system regardless of pipeline material selected. This system could increase the cost of construction, limiting the benefit of using materials such as timber that use manual construction methods. However, in view of pipe access for future operations and maintenance it is recommended that a trolley system, or some other means to provide safe work access to the pipeline for future maintenance, be implemented.
Removal and salvage of old pipeline
A number of options have been considered for the removal and salvage of the old pipeline. The two favoured options are to:
• Cut pipe into short sections, retaining by netting and lift by helicopter to a lay down area for dismantling; or
• Cut bands, dismantle staves and store on the pipeline route until subsequent removal by trolley during new pipeline construction phase.
On the basis that a trolley system is recommended for the construction of the replacement pipeline, the preferred option is to dismantle staves and stockpile on site. This option has the added benefit of maximising salvageable timber lengths.
Option 1 – Minimalist refurbishment of existing power station
Minimalist refurbishment of the existing power station represents a marginally economical viable outcome and potentially the best heritage solution. The proposed refurbishment would include repairs and modifications of at least five of the seven generators with the aim of allowing safe, unattended operation. This means that the station would be self protecting and it would be possible for the machines to shutdown safely if required and for the units to be shutdown remotely. Operators would be required to start the units and perform load changes. The station is currently geared for attended operation at all times. Enabling unattended operation would significantly increase the economic viability of the station.
The refurbishment scope would include a new control system to control the main inlet valve, governor, excitation, circuit-breaker and auxiliary systems. Refurbishment options are discussed in Section 4.1 of the main report and include possible changes to improve efficiency and energy output.
The option is available to replace all runner buckets upfront or replace some upfront and
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others progressively over a number of years.
The existing mechanical governors would no longer be used to control the turbines, but they would remain in situ to retain heritage value.
Option 2 – New Power Station
In evaluating the option of a new power station, consideration was given to different options for replacement generators in the existing station and in a new adjacent station. The key alternatives evaluated were:
• One new machine (nominally 10 MW) in the existing power station;
• Three smaller machines of nominally 10 MW total (3.3 MW each) in the existing power station; or
• One new machine (nominally 10 MW) in a separate power station adjacent to the existing power station.
A new 10 MW machine in the existing power station is considered unviable due to difficult access, limited space, lack of details on foundation structure and inadequate crane capacity.
The option to incorporate three smaller machines totalling approximately 10 MW would require removal of at least three existing generators. This option was dismissed based on the additional cost of plant, inadequate crane access and risk issues associated with a lack of details on the foundations.
The best option for a new generator is, therefore, a separate power station adjacent to the existing station. This arrangement is marginally economically viable and has a similar expected rate of return to the option of minimalist refurbishment of the existing power station (see Table 1). The best new generator option, based on budget prices from machine suppliers, appears to be a vertical shaft Pelton turbine and direct coupled generator.
The current cost estimates include provision for a station crane capable of lifting the heaviest machine component. This was adopted, rather than using a mobile crane, due primarily to weather considerations, where the roof would be required to be removed for extended periods during major works. This could be reviewed during any detailed design as a cost saving measure.
These generator options would require further consideration regarding heritage impacts if they were to progress to a detailed design phase.
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Consideration of generator sizes
The upper power station has an overall capacity of 8.4 MW, consisting of seven Pelton machines each having a capacity of 1.2 MW. An investigation was carried out for the potential to incorporate larger generator sizes. The size of the hilltop pipeline constrains the maximum flows as there is a risk of negative pressure in the pipeline which could cause significant damage. Utilising existing flows, the increased efficiency of modern machines allows for a maximum generator of around 10 MW. Significantly increasing the size of the current hilltop pipeline to accommodate a larger generator is economically unviable.
Common components
Condition assessments have shown that the penstock and dam are in a reasonably sound condition and do not require major upgrades. Some work is recommended on the dam including minor crest raising works and leakage repairs. This work is proposed regardless of redevelopment and heritage approval has already been granted.
Transmission connection requirements
For the option of refurbishing the existing power station, the arrangement could be to continue with the existing connection at Copper Mines of Tasmania providing an agreement can be reached between the parties involved. This would enable minimal capital expenditure and could provide Copper Mines of Tasmania with an alternative power supply.
For the option of a new power station, it would be preferable to connect into the Transend substation at 22 kV in view of modern protection infrastructure.
Tourism
Neither of the redevelopment options should alter the potential tourism opportunities. Site access would be temporarily restricted during construction and longer term access to the village, power station and hilltop track would need to be negotiated with any future tourism operator.
Hydro Tasmania intends to call for expressions of interest from parties for the development of tourism opportunities at Lake Margaret.
Environmental impacts
No significant environment impacts are associated with either of the proposed redevelopment options.
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Construction work associated with redevelopment would be completed under the direction of a comprehensive Environmental Management Plan.
Construction timing
Both options are likely to take until mid 2009 to commission due to equipment procurement lead times.
Under the current rules for RECs, for the Lake Margaret Power Station to become eligible for RECs for all of its production it would need to be shutdown for three years, and at least 50% of the cost of the same station built on a greenfield site be reinvested into a redevelopment. This would require the station to remain decommissioned until July 1, 2009.
For this reason, only the option of a new power station (Option 2) qualifies for full RECs. The minimalist refurbishment (Option 1) would cost less than 50% of a scheme replacement cost.
Next steps
• Seek feedback from the Lake Margaret Community Liaison Group regarding the analysis and findings in this Feasibility Study.
• Incorporate feedback from the community response.
• Progress Works Application and appeal to Resource Management and Planning Appeal Tribunal (RMPAT) for removal of the existing woodstave hilltop pipeline.
• Hydro Tasmania will call for expressions of interest for tourism development at the site.
• Board decision on business case and future options for the redevelopment.
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CONTENTS
1. Introduction 1 2. Background on the Lake Margaret Scheme 3 2.1 Physical description of scheme 3 2.2 Historical background 3 2.3 Present condition 6 2.3.1 Upper power station 6 2.3.2 Woodstave pipeline 16 2.3.3 Penstock and surge pipe 21 2.3.4 Dam 22 2.3.5 Outlet works at dam 23 2.3.6 Tramway 24 2.3.7 Hilltop valve 25 2.3.8 Haulageway 26 2.3.9 Lower Power Station 26 2.4 Heritage 26 2.5 Tourism opportunities 28 3. Redevelopment Options 29 3.1 Selection of options 29 3.2 Option 1 - Minimum upgrade utilising the existing power station and machines 29 3.3 Option 2 - New machine(s) with a similar capacity to the existing machines 30 3.4 Consideration of other options 30 3.4.1 Options considered in previous studies 30 3.4.2 Pump storage development 31 4. Option 1 - Minimum Upgrade Utilising the Existing Power Station and Machines 32 4.1 Generating sets 32 4.1.1 Turbines 32 4.1.2 Generators 34 4.1.3 Governors 36 4.1.4 Hydraulic power units 36 4.1.5 Excitation 37 4.1.6 Controls and metering 37 4.1.7 Electrical protection 39 4.1.8 Bearings 39 4.1.9 Turbine inlet valves 40 4.2 Station services 41 4.2.1 AC power 41 Hydro Tasmania Page xii
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4.2.2 DC power 41 4.2.3 Crane 42 4.2.4 Station ventilation 42 4.3 Tailrace 42 4.4 Switchgear 43 4.5 Transformers 44 4.6 Powerhouse viewing platform 44 5. Option 2 - New Machine with a Similar Capacity to the Existing Machines 46 5.1 New generating sets 46 5.1.1 Increased generator size 46 5.1.2 Machine type 47 5.1.3 New generating set(s) in the old powerhouse 47 5.1.4 New generating set in a new building 50 6. Components Common to Both Options 53 6.1 Dam works 53 6.2 Outlet works at dam 53 6.2.1 Bulkhead gates and screens 55 6.2.2 Outlet valves 56 6.2.3 Interconnecting valve 58 6.2.4 Sluice valve 59 6.2.5 Air valves 59 6.2.6 Outlet conduits 60 6.2.7 Power supplies, controls and communications 60 6.3 Replacement of hilltop pipeline 61 6.3.1 Removal of existing woodstave pipeline 61 6.3.2 New pipeline alignment 62 6.3.3 Pipeline material and installation method 62 6.3.4 Pipeline operation 64 6.4 Penstock and surge pipe 65 6.5 Hilltop valve 66 6.5.1 Air release and anti-vacuum valves 68 6.5.2 Power supplies, controls and communications 68 6.6 Access to hilltop 68 6.6.1 Haulageway 68 6.6.2 4WD access road 69 6.7 Preservation of sections of existing woodstave pipeline 69 7. Transmission Arrangement 71 8. Legislative Approvals 72 8.1 Introduction 72 8.2 Commonwealth 72
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8.2.1 Environment Protection and Biodiversity Conservation Act 1999 72 8.3 State 72 8.3.1 Environmental Management and Pollution Control Act 1994 72 8.3.2 Land Use Planning and Approvals Act 1993 and the Historic Cultural Heritage Act 1995 73 8.3.3 Threatened Species Protection Act 1995 74 8.3.4 Aboriginal Relics Act 1975 74 8.3.5 Forest Practice Act 1985 74 8.3.6 Building Act 2000 75 8.4 Summary 75 9. Environmental Assessment of Proposed Redevelopment Options 76 9.1 Introduction 76 9.2 The replacement of the hilltop pipeline 76 9.3 Potential environmental impacts as part of construction 76 9.4 Environmental flows in the Yolande River 76 9.5 Other environmental issues 77 9.6 Increased use of the site 77 10. Economic Analysis of Redevelopment Options 79 10.1 Options comparison 79 10.2 Risk assessment 79 10.3 Impact of Mandated Renewable Energy Target 80 11. Conclusions and Recommendations 82 12. Glossary 83 13. References 86
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LIST OF FIGURES
Figure 2-1 Old photo of dam area 4
Figure 2-2 Lake Margaret machines 7
Figure 2-3 Transformer yard and power station 13
Figure 2-4 Lake Margaret Power Station and Penstock 14
Figure 2-5 Hilltop woodstave pipeline with multiple leaks 17
Figure 2-6 Typical concrete support 18
Figure 2-7 Typical steel support 18
Figure 2-8 Penstock and haulageway 21
Figure 2-9 Lake Margaret Dam 23
Figure 2-10 Tramway 25
Figure 6-1 Existing dam outlet arrangement 54
Figure 6-2 Future dam outlet arrangement 54
LIST OF TABLES
Table 1 Economics of favoured options v
Table 2 Rationale for refurbishment versus new power station v
Table 2-1 Finite Element Analysis of Woodstave 20
Table 10-1 Economics of favoured option 79
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1. INTRODUCTION
Hydro Tasmania acquired the historically significant Lake Margaret Power Scheme in 1985 from the Mt Lyell Mining and Railway Company, but did not assume control until 1994. In that year, a series of investigations led to the closure of the lower power station and the retention of the upper power station under full manual control.
A number of studies have been previously completed on the redevelopment of Lake Margaret. The main reports of interest are the Lake Margaret Redevelopment Study Phase 1 of 1994 (Ref. 1), the Lake Margaret Redevelopment Study 2 of 2002 (Ref. 2), the Lake Margaret Power Station Upgrade Study of 2003 (Ref. 3) and the Lake Margaret Power Scheme – Summary of Reports on Redevelopment Options of 2005 (Volume 2, Appendix 1).
The Lake Margaret Redevelopment Study 2 of 2002 (Ref. 2) concluded that the best use of the available hydro resource was at the present upper power station, although a full analysis of the most appropriate machinery to put in place, and where, was not undertaken. Hence, the Lake Margaret Power Station Upgrade Study of 2003 (Ref. 3) was commissioned to follow-up on the 2002 study. The aims of the 2003 study were to conduct a more detailed comparison of replacement options with the potential for upgrading the existing generating plant at the upper power station and re-examining the redevelopment potential of the lower power station. Proposals for the lower station included redevelopment to the original design with outflow coming from the upper station and an alternative of extending the upper penstock to directly feed the lower station.
The options for the lower station were found to be uneconomic because the costs associated with both alternatives could not be justified in terms of the small amount of power generated. The recommended option from the 2003 study was the construction of a new station adjoining the existing upper station and containing a new Pelton turbine and generator.
Findings from the previous feasibility studies have been used to focus options development, taking into account more extensive condition assessments of the scheme components, together with changed market conditions and external drivers including:
• Basslink is now in place, resulting in the increased importance of system capacity.
• Renewable Energy Credits (RECs) are available until 2020.
• The Lake Margaret Power Scheme has been provisionally entered on the Tasmanian Heritage Register.
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The aging power station was closed on 30 June 2006, principally due to safety concerns regarding the hazards of constant repair of and access to the woodstave hilltop pipeline.
Hydro Tasmania has commissioned this feasibility study to determine the best long-term strategy for utilising the energy potential of Lake Margaret with consideration to economic, heritage, environmental and social implications of the options available.
An analysis of the redevelopment options is included in Section 3.
Funding options for the redevelopment have not been addressed in this study.
Preparation of this study has included development of concept designs by Hydro Tasmania, review of those designs (Volume 2, Appendix 2) by Snowy Mountains Engineering Corporation (SMEC), and preparation of construction cost estimates and risk review by independent engineering consultants, Johnstone McGee and Gandy (JMG), with inputs from suppliers of steel, timber and fibreglass pipelines and suppliers of hydro electric turbine/generator sets. International woodstave pipeline experts were also engaged to review the existing pipeline condition and provide estimates of replacement pipeline costs.
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2. BACKGROUND ON THE LAKE MARGARET SCHEME
2.1 Physical description of scheme The Lake Margaret Power Scheme is one of the oldest hydropower schemes in Tasmania. The scheme is based on the catchment of a small glacial lake of the same name, located in the coastal ranges north of Queenstown in a region of very high rainfall.
The scheme consists of the following major assets:
• Lake Margaret Dam (post tensioned concrete gravity dam);
• King Billy pine woodstave pipeline, transporting water from the dam to the penstock;
• Penstock;
• Upper power station;
• Lower power station, decommissioned; and
• Lake Margaret Village, including 7 cottages and a community hall.
The upper power station contains seven Pelton machines each having a capacity of 1.2 MW. The overall station capacity is thus 8.4 MW with a flow rate of approximately 3.4 m3/s.
The lower power station was decommissioned in 1994. It had been constructed in 1932 to re- use the water passing through the main station. It had a single Francis machine with a capacity of 1.5 MW.
The average gross annual energy production from Lake Margaret is 49 GWh (MRET baseline is 45.9 GWh due to application of 0.93 marginal loss factor). This represents an average of just over 5 MW production over the whole year or about 0.5% of the State’s total electricity output.
A summary of scheme data is provided in Volume 2, Appendix 3 Scheme Data.
2.2 Historical background The scheme was built and initially operated by the Mt Lyell Mining and Railway Company Ltd to supply power to its nearby Mt Lyell mine. The mine had operated for around 30 years utilising timber supplies in the area before looking to provide a more permanent and renewable source of power, with the Lake Margaret Power Scheme first producing power in 1914.
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The scheme has been identified as an area of outstanding heritage significance (see Ref 8). It is an example of the pioneering period of hydro-electric development in Australia and contains rare, state of the art, early twentieth century power generating equipment. Due principally to its private ownership and continuous operation for most of its life, the location has retained nearly all of its early infrastructure and equipment. It was provisionally listed on the Tasmanian Heritage Register on 4 August 2006 under all seven of the criteria set out in the Historic Cultural Heritage Act (HCHA) 1995. Under the HCHA, all the works must be approved by the Tasmanian Heritage Council.
Figure 2-1 Old photo of dam area
The power scheme development started with a 4.8 m gravity dam on Lake Margaret at the exit to the Yolande River. A 1.22 m diameter Oregon pine woodstave pipeline ran about 2200 m and fed two 915 m long riveted steel penstocks. The penstocks descended about 300 m to the Lake Margaret Power Station where they fed four Pelton turbines. The water was returned to the Yolande River running alongside the power station. Power was exported at 6.6 kV via two circuits to the Mt Lyell mine switchyard about 10 km away.
A permanent village quickly replaced the temporary construction village and the power scheme was so successful that it was decided to increase its size just one year after construction. However, with World War One erupting in Europe, it was impossible to obtain parts. It was not until 1918 that the station was extended, with an additional penstock and two further turbine generators. At this time, the dam was raised to 11 m (its current height)
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bringing the total storage to 15.2 million cubic metres. After its enlargement, the dam consisted of two independent portions separated by a conglomerate rock outcrop.
The catchment was enlarged slightly in 1930 by the diversion of Lake Peter, 2.5 km east of Lake Margaret. Also in this year, the power station was extended and a seventh similar turbine was added, bringing the capacity to 8.4 MW (the current configuration).
In 1932, demand for power saw the construction of the lower power station. A new weir, woodstave pipeline, steel penstock and power station were constructed downstream of the main station to re-use the water passing through.
A third 6.6 kV transmission line was added in 1935.
In 1938, the Oregon pine woodstave pipeline (upper pipeline) was replaced with the present King Billy pine woodstave pipeline.
The connection of Queenstown to grid power in 1948 removed the need for additional power from Lake Margaret, effectively freezing the station in its configuration until the present day.
Both stations remained relatively unchanged until 1964 when the tramway was replaced by an access road with the broader removal of the tramway system around Queenstown.
By 1970, the main station required upgrades and the following changes were implemented over the next decade:
• Replacement of the three small penstocks with a single 1.22 m diameter penstock, with associated head works and connections into the station.
• Dam upgrades to overcome general deterioration and leakage problems, including installation of prestressing cables in the dam to allow for uplift forces within the body of the dam (which were not allowed for in the original design).
• Installation of two new double circuit power lines with steel towers and four 6.6 kV to 11 kV autotransformers to increase the transmission voltage.
• Replacement of some of the outdated equipment.
The final modification, prior to the change of ownership in 1985, was the replacement of the main machine control panels in the station.
The 1980s was a difficult time for the Mt Lyell mine because of a drop in world copper prices. In 1985, the scheme was sold by Renison Goldfields Ltd, the owners of the Mt Lyell Mining
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and Railway Company Ltd, to the Hydro-Electric Commission through the Tasmanian Government. The sale helped to cover accumulated debts and to finance further exploration.
Although ownership was officially transferred in 1985, it was not until 1994 that Hydro Tasmania assumed control of the power scheme, retaining the existing operators under contract and embarking on a number of safety and reliability upgrades.
In 1994, the lower power station was decommissioned and mothballed following an investigation that revealed the cost of refurbishing outweighed the generation that could be achieved. Mothballing enabled heritage values to be preserved to the extent possible for a non-operating plant.
For more detail on the history of the scheme see Ref. 4 and 5.
A Conservation Management Plan (CMP) was prepared in March 2006 by Paul Davies (Ref. 5). The CMP identifies and prioritises the heritage values (from very high to low) of all the elements in the scheme and how best to retain those values for a range of future options.
The upper power station was closed on 30 June 2006. Safety concerns were a major influence in the recommendation to cease operation at that time; primarily these were concerns regarding the woodstave hilltop pipeline, which had been assessed as being at end of life and at risk of failure. The fully manned operation was also unduly labour intensive for a small station by contemporary standards.
A Care and Preservation Plan was put in place after the closure of the upper power station to ensure that the shutdown was completed in a way that preserved the significant heritage values of the site.
2.3 Present condition
2.3.1 Upper power station
2.3.1.1 Turbines
All seven turbines are horizontal shaft single jet Pelton turbines with a jet deflector and two shaft bearings. The units ‘A’ to ‘E’ are identical Boving turbines, unit ‘F’ is similar but was supplied by James Gordon and differs in detail design, and unit ‘G’ is a Boving turbine but about 20 years younger and also differs in detail design from the others.
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Figure 2-2 Lake Margaret machines
Some turbines have problems with sticking of the spears, which are closed by a spring action, rather than mechanical assistance from the governor oil hydraulics. These problems may be due to sticking of the spear itself or could be caused by the spear operating mechanism linked to the governor. The operators occasionally need to apply mechanical leverage to open and close a turbine spear.
The turbines, as supplied, had a rated power output of 1750 BHP (1305 kW) at a net head of 1050 feet (320.04 m) and a speed of 500 rpm, and an overload capability of 1925 BHP (1435 kW). The generators have, in recent times, been limited to 1200 kW to limit winding temperature and this has, consequently, limited the turbine output.
The turbines have had an ongoing history of runner bucket failures since first going into service. Damage is believed to originate from corrosion fatigue because they undergo cyclic loading and are always wet when in service. In the past, parts from failed buckets would regularly pierce or fracture the original cast iron turbine runner covers, and these have since all been replaced by fabricated steel covers. They have also damaged the turbine pit lining.
There are currently a variety of bucket ages and materials including cast steel, austenitic stainless steel and martensitic stainless steel. When the station was in operation, routine turbine runner bucket inspections were conducted and, where required, weld repairs or complete bucket replacements were completed.
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The original turbines retain cast iron inlet bends and nozzle housings. The newer penstock distributor and newer inlet valves installed in the 1970s have a design pressure of just over 400 m water head, the original cast iron turbine pipes appear to have a design pressure of only 352 m (500 psi). This is a maximum allowable pressure - only 3% above the maximum static head or pressure at the station turbine inlets. In addition, a section mid-way along the new penstock has been identified with a maximum allowable pressure very near the maximum static at that location.
These two pressure restrictions mean that the existing turbines should produce very little pressure rise when closing their spears during shutdown. Currently, the turbines have a nominal spear closure time of 20 seconds, although tests have confirmed that it varies widely between units. Preliminary hydraulic transient modelling indicates that the seven turbines simultaneously rejecting load in 20 seconds causes higher than acceptable pressures at the turbine inlets and at mid-penstock. It also causes the existing surge pipe to overflow. In practice, the over pressure and surge pipe overflow is generally avoided because the lake level is lower (less than seven units are operating) and a number of the turbines stick open and go to runaway speed rather than being controlled by their governor and rejecting load.
The turbines have almost no electrical interfaces and no automatic protection of any kind. Turbine monitoring and protection relies on detection and action by a station operator.
A summary of the condition assessment is given below:
• Not all machines share the same runner bucket profile or number of buckets.
• Unit ‘E’ has been mothballed so its runner buckets are used as spares for some of the other machines.
• Turbine runners and shafts are subject to corrosion fatigue and could potentially fail catastrophically.
• The tailrace concrete, the runner pit steel lining and the steel turbine foundation beams are all in very poor condition.
• Currently no automatic protection (eg bearing over temperature, turbine overspeed, low governor oil pressure, vibration).
• Some efficiency may be gained by modifying the spear tip and nozzle angles.
• Some efficiency can be gained by adopting a new bucket hydraulic shape.
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• Modern efficiency levels can be gained by a combination of new injector assembly and new runner.
2.3.1.2 Generators
The generators are all two-bearing open frame machines with the windings completely exposed to the station environment. They are driven via leather belt flexible shaft couplings, with the exception of ‘G’ machine which has a rigid coupling. All generators are identical General Electric 1500 kW, 12 pole, 500 rpm and 6.6 kV.
A summary of the condition assessment is given below:
• The windings are vulnerable to possible damage from water due to roof leakage, moisture, dust, insect ingress and vermin, as well as lightning.
• Although the generating voltage is 6.6 kV, the surge arrestors on the machine terminals are rated higher. Consequently, the generator windings can be subject to voltage well in excess of 6.6 kV in the event of a lightning strike.
• The general condition of the windings appears acceptable, however the general age of the windings, patch repairs (coil repairs/replacements) and the variable insulation resistance (IR) readings indicate the windings could require a fair degree of maintenance to maintain generator operations. This an acknowledged risk of Option 1.
2.3.1.3 Governors
The governors are powered by oil pressure provided by an internal oil pump, which is driven by a flat belt from the main turbine shaft. The governor output shaft moves a series of linkages which open the deflector and the spear which has an integral closing spring. The governor speed reference is provided by a second set of belts from the main turbine shaft which drive the centrifugal ball head governor.
A summary of the condition assessment is given below:
• The governors do not have a shutdown solenoid that could be used for automatic or emergency shutdown sequences.
• Speeder motors are the original units. Minor engineering would be needed to fit a modern equivalent.
• Poor condition of the governor and its internal servomotor frequently prevent deflector operation during load rejection, allowing the machines to runaway.
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• No automatic inlet valve operation is available as backup in case of governor failure.
2.3.1.4 Controls and metering
There are very few control systems for the station with the vast majority of necessary actions being either performed or initiated by the operators.
The current control panels were installed during the early 1970s and are in good order. A programmable logic controller (PLC) system was installed in 1999 to provide some alarming functions where there had previously been none.
2.3.1.5 Excitation system
The original excitation systems for this station were via individual rheostats from a common supply provided from three house sets with DC generators. Since then, a system of individual thyristor rectifiers (electroplating rectifiers), fed from the station services transformers, has been implemented. Three of the rectifiers are supplied from one services transformer and the other four rectifiers are connected to the other services transformer. To enable the power station to be started without an external power source a switch has been provided to connect the field of the ‘B’ generator to the original common DC generators which have been retained for this purpose and emergency DC lighting.
A summary of the condition assessment is given below:
• The rectifiers are in poor condition with a poor maintenance history and have had a number of failures.
• The rectifiers are based on discrete analogue electronics, early PCB technology.
• The excitation systems are not ideal for the application.
• The electrical protection is limited with only generator overcurrent protection. There is no loss of field (pole slip) or over excitation protection.
• Spares are scavenged from an out of service unit.
2.3.1.6 Bearings
Each generating set has four white metal bearings lubricated by two rolling oil rings which bring up oil from the oil reservoir below the bearing.
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There have been many bearing failures due to sticking of the rolling oil rings and it is not known whether the failure of one ring could threaten the bearing or if the bearing could operate satisfactorily on one ring. An oil level sight glass is provided.
A summary of the condition assessment is given below:
• No bearing over temperature indication or automatic protection.
• No vibration monitoring or automatic protection.
• Bearing failure if undetected can lead to catastrophic machine failure.
2.3.1.7 Main inlet valves
Each machine is fitted with two 15” NB turbine inlet valves in series. The valves are tapered wedge gate valves with AC driven Rotork actuators. These valves were supplied new at the time of the penstock replacement in the 1970s.
There have been problems with the metallurgy of the valve stems, several of which have failed. Laboratory reports identified a brittle failure problem and it is not known how many of the valves have had replacement stems fitted. These failures had been attributed to poor adjustment of the limit switches, resulting in jamming of the disc in its tapered seat and, since proper adjustment, there have been no more reported failures. Apart from this, the valves generally operate well, and have successfully closed into turbine flow.
A summary of the condition assessment is given below:
• Actuators are 30 years old, starters have failed. Replaceable - in reasonable order although five are located outside.
• Tapered wedge valves of this type are not intended to close frequently against an appreciable flow. In an automatic system the turbine spear should be closed before the valve, except in an emergency, when it would be essential to close against flow.
2.3.1.8 Switchgear (6.6 kV)
The station has a two section 6.6 kV bus arrangement with two auto-transformers and one of the station services transformers on one section (with four generator circuit-breakers (CBs)) and the remaining two auto-transformers and the other station services transformer (along with three generator CBs) on the other section. A bus tie breaker is usually left open, but can connect the two bus sections together if required.
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The machine circuit-breakers were upgraded in 1984, with high reliability in operation and the external appearances are in good order, except for the machine ‘G’ circuit-breaker.
A summary of the condition assessment is given below:
• CB ‘G’ has low reliability in operation.
• The circuit-breakers are bulk oil design and located within the power station so they present a fire risk. There is no fire suppression within the cabinets or in the room (except for a portable fire extinguisher), and the emergency exit is not up to standard with only one exit located at the end of the room.
• Local operation of the CB requires the operator to be standing in front of the CB, exposing the operator to harm in the event of a fault.
• The older auto-transformer and bus-tie CBs are likely to present a higher fire risk than the generator CBs due to their internal construction design; comment given as “unlikely to be of arc fault containment design”.
• Considering the age and the general condition of the CBs, their general life expectancy is about 10 years. However, if there is an opportunity for replacement, the CBs should be replaced with CBs of different type to reduce the fire risk.
2.3.1.9 Transformers (6.6 kV/11 kV)
The four transformers are all autotransformers with different dates of manufacture; transformers ‘A’ and ‘C’ are 1970, transformer ‘B’ is 1987 and transformer ‘D’ is 1992.
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Figure 2-3 Transformer yard and power station
Transformer ‘B’ has a fault and is out of service. Oil analyses of all four autotransformers indicate the transformers are PCB free, however the furans analysis indicates that transformers ‘A’ and ‘C’ are nearing the end of their service life.
The transformers earthing was upgraded as part of the earthing upgrade in the late 1990s and new surge diverters were installed to help limit the lightning surges onto the generator bus.
The use of autotransformers for generating sets is not preferred as they do not provide the isolation from the transmission lines that would help prevent lightning surges being transferred directly to the generator windings.
A summary of the condition assessment is given below:
• Transformer ‘B’ is already out of service and could require replacement if the station is to return to service; particularly if any efficiency improvements are made to the machines leading to increased station output.
• Transformers ‘A’ and ‘C’ are nearing the end of their service life and replacements need to be considered in the near future if the station is returned to service.
• For any single transformer replacements, the simplest option would be an autotransformer. However, if all four transformers are to be replaced then two winding
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transformers should be installed. In conjunction with possible CB replacements, the four autotransformers could be replaced with a single two winding transformer, though the transformer yard structure would need to be checked for the concentrated loading of a single transformer.
2.3.1.10 Powerhouse and tailrace
An inspection of the powerhouse and its tailrace was undertaken. The detailed Upper Station and Tailrace Inspection report for this inspection is provided as Volume 2, Appendix 4. There was insufficient information (eg design drawings) to enable detailed structural analysis, therefore the inspection was restricted to a visual inspection only.
Powerhouse
The main elements of the building appear to be in a satisfactory condition.
Vertical and diagonal cracking is evident in the upper part of the structure. These vertical cracks exist in symmetrical locations around the building, approximately one quarter of the way from the end along each of the longer walls. These cracks generally extend from the upper windows to the top of the wall and down approximately 3 m from the windows.
Figure 2-4 Lake Margaret Power Station and penstock
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Southern extension
The southern part of the powerhouse was extended in 1930 to accommodate the 7th machine. This extension consists of steel columns, timber wall and roof purlins and corrugated iron cladding.
The bracing detail on the south end wall is poor. The bracing should extend diagonally from the floor to the roof in a single or multiple run.
There is no diagonal bracing present on the east and west facing walls of the extension.
The cladding on this extension appears to be in good condition.
Roof trusses
The trusses appear to be in a satisfactory condition.
The bottom chords appear to be undersized for the relatively wide span of 12 m, leaving them susceptible to compression loads.
Cladding
The cladding on the station roof and the extension to the south end of the building appears to be in good condition.
Asbestos
Asbestos products have been used in the building. A report was prepared in 2002 by Airport Engineering and Contracting that assessed asbestos related issues. An asbestos and condition inspection was carried out on July 2006 by Injury Prevention and Management (IPM) together with preparation of an asbestos register. This register will guide safe redevelopment and operation and maintenance.
Crane
The station crane is an overhead travelling bridge crane with travel and traverse motions. It is the original crane installed when the power station was built and all its motions and hoist are manually powered by chains from the machine floor level.
The original crane rating was 15 tons, but in the last decade it has been de-rated to 9 tonnes. Currently the main hoist has a broken operating mechanism, and its chains have been removed to prevent its use. A 5 tonne auxiliary hoist has been added and operates from a mono-rail trolley running along the bottom flange of one of the main crane beams.
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In the original building, the crane girder is 450x150 UB and rests on concrete beams. The weight of the crane is transferred as a vertical load to the concrete beam. However, the lateral surge from the crane creates torsion in the steel beam and this torsion may produce a lateral twist of the top flange of the girder. This might be the reason for the lateral sway of the girder.
Tailrace
The original riveted iron and/or steel turbine pit lining that extends down towards the tailrace is severely corroded; completely through to concrete in some areas, and has been damaged by runner bucket failures. The steel beams partly embedded in concrete below the turbines are also severely corroded and well beyond the end of their effective life. The concrete lining in the existing tailrace channel is in poor condition. There is no observable exposed steel reinforcement, which indicates that there may be little or no original steel reinforcing in this concrete.
2.3.2 Woodstave pipeline
Continued operation of the 68 year old woodstave pipeline is no longer considered to be viable due to the high risk of failure. During later periods of operation, the pipeline required more frequent repair for minor failures. An assessment of the condition of the woodstave pipeline, in May 2001, recommended that it should be withdrawn from service before the end of 2003. Due to its high heritage significance and, as it was integral to any final option chosen for the upgrade or redevelopment of the scheme, the pipeline continued operating up until the station closure in June 2006.
As part of this current review, Hydro Tasmania commissioned engineering consulting firm, Sinclair Knight Merz (SKM) to provide a report on the condition of the existing woodstave pipe (Ref. 6). SKM concluded that the existing pipeline had reached the end of its useful life and, therefore, continued operation of the scheme was, at a minimum, reliant on a replacement pipeline.
In view of this analysis, Hydro Tasmania engaged Canadian woodstave pipe and barrel manufacturer, Canbar, to provide a report on the current woodstave pipeline (Ref. 7) and provide advice on construction of a potential replacement pipe (Volume 2, Appendix 5). Canbar concluded that the current pipe has reached the end of its life and should be decommissioned.
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A report was also commissioned on the specific condition of the timber in the woodstave pipeline. This study by, Acutel Consulting (Volume 2, Appendix 8) included sampling and analysis of over 222 core samples. This report indicated that timber thickness and quality has deteriorated significantly, particularly in the top half of the pipe. Average thickness in the top half is now 29.6 mm with 33.4 mm in the bottom half compared to an original thickness of 48 mm. Although significant amounts of timber have deteriorated to the extent that any service life is problematic, there appears to be a salvageable quantity of King Billy pine that could be recycled for use as craft wood or other alternatives. Forestry Tasmania (Volume 2, Appendix 6) has assessed that approximately 90 m3 of ‘select’ boards may be salvaged. Another 30- 45 m3 of second-grade boards may also be produced.
Hydro Tasmania conducted a detailed condition assessment of the woodstave foundations and supports and concluded that the foundations are generally in poor condition. It is considered the existing foundations would be of little value as part of any replacement pipe construction.
Figure 2-5 Hilltop woodstave pipeline with multiple leaks
2.3.2.1 Woodstave pipeline supports
The woodstave pipeline starts just downstream of the Lake Margaret Dam’s outlet and extends to just prior to the hilltop valve. The length of the pipeline is 2200 m and is supported by concrete and steel supports. Typical supports are shown in the following two photographs.
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Figure 2-6 Typical concrete support
Figure 2-7 Typical steel support
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Prior to this feasibility investigation, there was discussion of the possibility of reusing the supports for a new pipeline. A thorough visual examination of each support (594 in total) was undertaken to determine if this was possible.
The results of the investigation have shown that most of the supporting structures are in a poor state. It has been assumed that new foundations would be required for redevelopment options.
Details of the investigation are contained in Volume 2, Appendix 7 Lake Margaret – Woodstave Pipeline Support Inspection.
2.3.2.2 Woodstave thickness investigation
The current woodstave pipeline was constructed in 1938. This pipeline was constructed alongside the original (1914) pipeline. During construction of the 1938 pipeline,, the original 1914 pipeline remained in service to meet the electricity needs of the Mt Lyell mine. It was not taken out of service until the final stages of construction, when it was necessary to change over to the new pipeline. The 1938 pipeline was constructed from King Billy pine. Each stave was nominally 1” 7/8 inch thick x 6 inches wide. It is estimated that 22,000 staves were used.
A detailed investigation of the pipeline’s thickness was undertaken as a part of this feasibility investigation by Acutel Consulting. The findings of the 2006 investigation, in relation to thickness, are summarised below.
Total number of samples – 222 o Number of top samples – 40 Average top thickness – 29.6 mm
o Number of bottom samples – 108 Average bottom thickness – 33.4 mm
o Number of side samples – 74 Average side thickness – 31.6 mm
Overall average thickness – 31.5 mm. Original thickness 48 mm.
For a comprehensive discussion on the condition of the woodstave pipeline, refer to Volume 2, Appendix 8 Assessment of The Thickness and Condition of the Timber Staves in the Pipeline for the Lake Margaret Upper Power Station
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2.3.2.3 Structural assessment of the woodstave pipeline (Finite Element Analysis)
To complement the condition assessment of the woodstaves, a structural assessment of the pipeline was also undertaken. This assessment was performed using Finite Element Analysis (FEA) techniques. This assessment was undertaken to determine if the current pipeline could be safely recommissioned. Different machines have different pressure profiles. At the time of undertaking this assessment, it was not known what machines would be used. Therefore the assessment only considered the static condition. The main assumptions and results from the analysis are shown in Volume 2, Appendix 9.
The 2006 results have been based on the latest stave thickness measurements (average thickness 31.5 mm) for three different hoop conditions. The scenarios of all hoops in place, one hoop missing, and two consecutive hoops missing have been modelled.
The following are the results of FEA analysis. Factors of safety for the woodstaves are given as a range due to the expected variation in ultimate timber strength.
Table 2-1 Finite Element Analysis of Woodstave
Case Woodstave stress Hoop stress (MPa / factor of safety) (MPa / factor of safety) Original design 48 mm 10 MPa / 3.2 – 5.2 130 MPa / 1.9 All hoops in place 2006 average stave 22 MPa / 1.4 – 2.3 130 MPa / 1.9 thickness – 31.5 mm No hoops failed 2006 average stave 28 MPa / 1.1 – 1.9 147 MPa / 1.7 thickness – 31.5 mm (Between the remaining (Stress at the adjacent hoop) 1 hoop failed hoops) 2006 average stave 50 MPa / 0.64 – 1.04 195 MPa / 1.3 thickness – 31.5 mm (Between the remaining (Stress at the adjacent hoop) 2 adjacent hoops failed hoops)
These results show:
• The original woodstave was likely to have been designed with a relatively high factor of safety for the timber staves. However, the factor of safety for the hoops was relatively low.
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• Results using the average 2006 woodstave thickness are concerning, as the factors of safety have dropped considerably below what could be considered a comfortable range.
• Although hoop failure is a relatively rare event, the failure of a hoop leads to stresses resulting in increased likelihood of failure of the staves or further hoops (and thus staves).
• Mitigative measures should remain in place that prevent people from working under, or in close proximity to, the pipeline (when full).
2.3.3 Penstock and surge pipe
The upper power station penstock and distributor were constructed in 1970 and retain their original coatings. The surge pipe was constructed around the same time.
Figure 2-8 Penstock and haulageway
A detailed condition assessment of the penstock and surge pipe was undertaken. This assessment consisted of non-destructive testing (NDT) using ultrasonics, to determine the existing pipe shell thickness, and a visual examination (internal and external) to determine the condition of the penstock’s protective coatings.
The details of each assessment are contained in Volume 2, Appendix 10 Hydro Tasmania Lake Margaret Penstock, Pipe Thickness Readings, Non Destructive Testing, Volume 2, Appendix 11 Record of Inspection – Surge Pipe and Volume 2, Appendix 12 Record of Inspection – Penstock and Hilltop Valve.
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The findings from this investigation were:
Penstock
• A short section of penstock (at top and bottom) was inspected on 11 October 2006 and found to be in good condition.
• Pipe Shell Thickness: Maximum loss was 2.14 mm in pipe No.1 at top and 0.43 mm loss in pipe No. 61 (highest stressed pipe).
• Internal coating was confirmed as being coal tar epoxy.
Surge pipe
• The lower section of the surge pipe where it is permanently submerged is in very good condition, but the upper (unpainted) section where it is periodically wet and dry is in very poor condition. Generally many of the upper pipes showed significant corrosion in the bolted joints at the invert. For example, at pipes 8 & 9 (from the top end) there is estimated up to 5 mm metal loss around much of the circumference of the pipe, within 15 mm of the bolted joint. The upper section of surge pipe is close to failure and there may be leakage in the near future.
• Surge pipe – 0.49 mm shell loss in lower section and 0.17 mm shell loss in upper section. Based on the internal inspection of the surge pipe, the recent ultrasonics pipe shell thickness readings do not reflect the serious corrosion at the bolted flanges (1.83 m pipe lengths), especially at the invert.
• Internal Coating: Coal tar epoxy in surge pipe lengths S1 to S5.
• Excluding pipes S1 to S5 the surge pipe could require replacing in the near future.
2.3.4 Dam
The dam consists of two structurally independent concrete gravity sections with vertical prestressing added in 1974. The dam is extensively cracked and various fissures have been enlarged to cavities 100-200 mm deep. Minor leaks exist when the lake level is high. There is widespread frost damage. The major factor affecting the longevity of the dam is the uncertainty regarding the condition of the prestressing cables. There is no evidence of any cable corrosion to date, however, it is difficult to ascertain the condition of the cables (Ref. 8). Thus, a decision to replace the cables may be required at some point in the future.
While the power station remains in a decommissioned state, there is a significantly increased risk of overtopping of the dam and hence an increased risk of dam failure. With the power
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station not operating, the spillway capacity is not sufficient to meet the relevant ANCOLD guidelines for the hazard category (Low) of Lake Margaret Dam. Crest raising (left-hand dam only) is proposed to increase the spillway capacity sufficiently to return the risk of overtopping to the pre-shutdown position. These modifications are proposed regardless of redevelopment.
Figure 2-9 Lake Margaret Dam
2.3.5 Outlet works at dam
2.3.5.1 Bulkhead gates
There are two bulkhead gates or stoplogs, each lowered vertically in a slot in the upstream face of the dam in front of each of the two conduits through the dam. The gates are lifted and lowered by a hand-operated hoist.
The gates are in fair condition apart from a 80NB hole through the centre which may have been used in the past with a valve to allow flooding downstream of the gate before opening.
A summary of the condition assessment is given below:
• Unknown quality of original iron castings.
• Increased lake level so increased head and load on gates since original design.
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• Lack of seals prevents rapid or reliable isolation of downstream conduits when bulkheads closed.
2.3.5.2 Trash screens
There are three sets of trash screens at each of the two intake conduits; one outer basket type screen and two inner screens mounted in cast iron guides embedded in the dam walls. Screens are a stainless steel mesh on a steel frame and are believed to have last been refurbished in 1991.
The screens should be retained as is, unless the station discharge is to be substantially increased.
2.3.5.3 Pipeline inlet valves
There are two cast iron gate valves, one for each conduit, each 1200 mm diameter. The valves are currently manually operated by handwheel. Operators report that they are in good working order, have been closed successfully against flow and unbalanced head.
The valves were originally electrically actuated, each by a 3-phase electric motor, and the actuators were manufactured by Mt Lyell. The power supply to the dam area is no longer in place and the electric valve actuation has been removed.
It takes approximately 1.5 hours for an operator to reach and close one of the valves in an emergency, 20 minutes from the power station to the hilltop, 30 minutes walk to the dam, and 40 minutes to manually close the valve. The emergency response time was a safety concern that contributed to the decision to close the station in June 2006.
Refurbishment of the valves is limited by the present inability to remove or dismantle the valves which have a total weight of 6 to 8 tonnes.
2.3.6 Tramway
The tramway runs for approximately 2200 m from the penstock to the dam. It is used as a walkway and a trolley also exists for the transport of heavy items. The tramway passes over 17 bridge structures, with the majority of these being near the dam end. Many of the bridge structures are severely corroded.
A condition assessment of the tramway was performed in June 2006. The results of this assessment are included in Volume 2, Appendix 13.
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Figure 2-10 Tramway
2.3.7 Hilltop valve
This hilltop valve was installed during the penstock replacement in 1971. It is a butterfly valve with counterweight close and hydraulic open. It is a 48” NB valve by M. B. John & Hattersley Ltd. That originally incorporated an over velocity trip paddle that mechanically tripped the valve. During operation by Mt Lyell, it was not used as an emergency valve and was permanently held open. During 1997, the hilltop valve was fitted with new hydraulics and recommissioned as an automatic valve.
The valve failed to close when tripped during a test in 2001. It eventually closed by an operator repeatedly working it in open and close directions. During flow closure tests in 2003 the valve stopped at about 2° from fully closed. Tests have revealed unacceptably high trunion friction in the valve. It is predicted that the valve may fail to close due to excessive trunion friction when closing the valve into flow with full lake level and maximum differential pressure across the closing valve.
The original over velocity paddle was not operational and has been removed. Currently the penstock protection is provided by detecting an excessively low pressure in the conduit at the valve location that should only occur due to excessive water velocity caused by a penstock burst. An air valve on a small chamber on top of the penstock near the valve would allow in
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air if the penstock pressure falls to below atmospheric, and a float switch in the chamber detects the water level dropping.
The electrical aspects of the valve are in good order.
2.3.8 Haulageway
The haulageway was installed during 1970 and was refurbished in 1997/98. The haulage has a rating of 1.5 tonnes and, in recent history, has been certified and registered with Workplace Standards Tasmania. The haulage can only be operated by a driver from the winch house at the top.
The winch was second-hand when installed and was manufactured by P. R. King & Sons of Marrickville, NSW, (serial number 1230) and its name plate rating is 4.5 tonnes. The track consists of two 30 lbs/ft rails supported by concrete or steel beams, one rail on each side of the penstock. The track is about 1000 m long and its average slope is 1 in 2.4. A single trolley straddles the penstock. The wire rope was replaced as part of an upgrade in 1997.
The winch electrics had a partial upgrade in 1997 and this work saw a variable speed drive installed to manage the speed control aspects. Much of the electrical equipment is still original.
Haulage is currently uncertified and, therefore, requires re-certification before it can be returned to operation. This requires NDT testing of the wire rope (x-ray) and removal of a short length of rope for destructive testing of ultimate tensile strength.
2.3.9 Lower Power Station
The Lower Power Station was shutdown and mothballed in 1994. “Mothballing” was recommended in the Lake Margaret Cultural Heritage Study by Godden Mackay (1994) (Ref 4), which advocated that both stations should remain as close as possible to working condition.
Most infrastructure outside the power station building and winding house has deteriorated, however, all infrastructure remains in situ.
2.4 Heritage Establishing the cultural heritage significance of a place assists in understanding what elements of the place contribute to that significance and the relative contribution of each element to the overall significance. This is essential to allow management of the place and
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can guide future work in a way that retains its significance. A number of statements of significance can be viewed in the Conservation Management Plan (CMP) prepared in 2006 (Ref. 5) however, a succinct statement of significance is provided below:
The Lake Margaret power station complex is a place of outstanding cultural heritage value. It encapsulates the early development of power generation in Australia and Tasmania and the pioneering enterprise of the West Coast of Tasmania that was integrally linked to mining development on a site of great natural beauty and value. The development of the Mt Lyell Mining and Railway Company mines (an icon mining venture in Australia) and Queenstown was dependant on the operation of the station.
The place is one of the earliest power schemes in Australia whose value is enhanced by its continued operation. It is the last privately built and operated scheme in Tasmania and marks a major change from private to public power generation in the State.
The site is a rare and intact example of not only the power generating plant with its rare set of early generating and control equipment but the associated infrastructure of dam, pipelines, headworks, the village and the very rare second station added in 1931.
Lake Margaret has the ability, more than any other hydro power station in Tasmania, to demonstrate all aspects of its history and operation within an accessible wilderness area. It is a place that has very high interpretative value.
The Lake Margaret Power Scheme was provisionally listed on the Tasmanian Heritage Register on the 4 August 2006 under the Historic Cultural Heritage Act 1995. The provisional listing and statements of significance arising out of this listing are still under review.
While the CMP provides broad direction for protection of cultural heritage values, a Heritage Impact Assessment (HIA) is usually prepared to assess the detailed impact of proposed works on the heritage significance of a place and can recommend actions to mitigate the impact on the heritage values of the place. Under Hydro Tasmania’s Environment and Sustainability Management System, an HIA is a requirement for sites of high or very high significance or where a CMP applies.
The provisional Tasmanian Heritage Register listing holds the same legislative requirement as a full listing. Legislative approvals are further discussed in Section 8.
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2.5 Tourism opportunities Hydro Tasmania commissioned a report giving an Indicative Assessment of Tourism Potential for Lake Margaret. This report was completed by Inspiring Place in June 2006 (Ref. 9). A summary of the Inspiring Place assessment is given below:
The opportunities for potential tourism and recreational use at Lake Margaret are limited, but are outlined below.
• Continued interest by the local community in a range of recreational activities including walking, fishing, fossicking and nature study;
• Day visits by independent users principally for walking (e.g. along the tramway and other tracks if developed) and cycling (e.g. the access road);
• Day visits as a special interest tour run by tourism operators that might include heritage (e.g. power station, village life, penstock) and soft adventure (e.g. short walk experiences especially if the haulageway along the penstock is operational);
• Overnight stays involved with the upgrading of the village buildings for use as visitor accommodation or educational/training group use.
Hydro Tasmania intends to call for expressions of interest from parties for the development of tourism opportunities at Lake Margaret. This will occur following finalisation of the redevelopment option.
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3. REDEVELOPMENT OPTIONS
3.1 Selection of options A review of all technically feasible redevelopment alternatives has been completed.
Based on review of the previous studies, the following two options were selected for detailed analysis in this feasibility study, for redevelopment of the upper power station:
1. Minimum upgrade utilising the existing power station and machines; or
2. New machine(s) with a similar capacity to the existing machines.
A number of other options were assessed in arriving at these two principal options, utilising work that had been done in previous feasibility studies such as those referred to in the Introduction. Details on these other options are provided in Section 3.4. Dismissed options include pump storage development.
The following components have been assessed in this study as common to both options:
• dam work including raising and leakage mitigation
• automated outlet valve operation (at dam) subject to a risk assessment and condition assessment of existing valve
• remote area power supply for dam area
• hilltop valve replacement or refurbishment
• maintenance of three sections of existing woodstave pipe
• replacement of woodstave pipe
• surge pipe upgrade
• remote SCADA access.
These common components are discussed in detail in Section 6.
3.2 Option 1 - Minimum upgrade utilising the existing power station and machines Option 1 involves completion of the headworks upgrades discussed above in Section 3.1 and refurbishment of the existing machines in the upper station.
The purpose of the upgrades would be to allow the station to run unattended, with the ability to automatically and safely shutdown machines without an operator being present in case of
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a fault or in an emergency. This would eliminate the need for shift work by allowing unattended operation.
Consideration has been given to continuing to operate the power station on a fully manned basis, with minimalist expenditure. Analysis shows that it is economically more viable to invest the capital up-front to make the station safe for unattended operation, rather than continue to pay for 24 hour shift operations.
To make the existing machines suitable for semi-automation, major upgrades and/or replacements have been recommended for the main inlet valves, governors, excitation systems, machine protection, and control systems.
Staff would still be required to start and load the machines and do routine checks at regular intervals.
3.3 Option 2 - New machine(s) with a similar capacity to the existing machines This option involves the installation of a new machine, nominally 10 MW. This option also involves the completion of the same headworks upgrades as for Option 1.
The turbine/generator system would include a command, control and protection system including generator and transformer protection, synchronous relay, lock-out relay, panel and supervision system. The control system would be purchased with the new machine and would utilise modern PLC based technology. All machines purchased by Hydro Tasmania in the last 30 years have been designed for automatic unattended operation and it is expected that the specification for a new machine would include similar facilities.
The new machine(s) could be located in the existing powerhouse or in a new powerhouse located at the present location of the penstock distributor between the existing station and the Yolande River. A new powerhouse could be annexed to the existing station so that only the minimum working space would be needed next to the machine, and other workshop, office and amenities facilities could continue to be provided in the existing building.
3.4 Consideration of other options
3.4.1 Options considered in previous studies
A good summary of all of the redevelopment options previously considered can be found in the Lake Margaret Power Scheme – Summary of Reports on Redevelopment Options document of 2005, which is included as an appendix to this report (Volume 2, Appendix 1).
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A number of redevelopment options have been considered in previous studies. The 2002 study, Lake Margaret Redevelopment Study 2 (Ref. 2) focused on the preferred options canvassed in the initial 1994 Phase 1 study (Ref. 1). It compared various upgrade options for the upper station, the lower station, and options for diverting the outflow of Lake Margaret into the Langdon Valley and on to the Anthony and Pieman Schemes. The preferred option was to upgrade the existing scheme by replacing the hilltop pipeline and upgrading or replacing the turbines in the upper power station.
In 2003, a further study of the redevelopment options was undertaken based on the previous findings. The Lake Margaret Power Station Upgrade Study (Ref. 3) examined the alternatives for upgrading or replacing the generating plant at the upper station site, re- examined the bypassing of the upper station by building a longer penstock to the lower station, and addressed suitable methods and the corresponding costs of transmitting the output of both stations to Queenstown. The preferred option identified in the 2003 study was the construction of a new station adjoining the existing upper station containing a new turbine and generator.
3.4.2 Pump storage development
Potential pump storage development at Lake Margaret has been considered as follows:
• Building a larger dam below the existing upper power station to enable a lower storage from which to pump to Lake Margaret; or
• Developing a pump storage arrangement between Lake Burbury and Lake Margaret.
The first pump storage option above can not be implemented as there is not a suitable location below the upper power station for the creation of a new storage of sufficient size from which to pump to Lake Margaret.
The second pump storage alternative requires approximately 6 km of tunnel and pipeline between Lake Margaret and Lake Burbury. The head difference between the two lakes is nearly 430 m. This option may become economic in the future if peak energy prices rise considerably above current values.
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4. OPTION 1 - MINIMUM UPGRADE UTILISING THE EXISTING POWER STATION AND MACHINES
Option 1 involves completion of the headworks upgrades discussed in Section 6 and refurbishment of the existing machines in the upper station.
The purpose of the upgrades would be to allow the station to run unattended, with the ability to automatically and safely shutdown machines without an operator being present in case of a fault or in an emergency. This would eliminate the need for shift work by allowing unattended running.
Staff would still be required to start and load the machines and do routine checks at regular intervals.
Under current RECs rules, if the Lake Margaret Power Station is shutdown for three years, and at least 50% of the cost of the same station built on a greenfield site is reinvested into a redevelopment, then it would become eligible for RECs for all of its production. The minimalist refurbishment option would not meet the requirement for 50% investment.
4.1 Generating sets The upgrade under this scenario would be to a minimal standard acceptable to Hydro Tasmania’s Power Schemes Group, based on:
• station islanded operation without operator active control not being required;
• unitised controls for units not being required;
• unattended operation required overnight and at weekends;
• generating units continuing to be manually started by an attending operator;
• any faults automatically shutting down the effected machine without operator intervention;
• The scope of work may not include all of the seven units.
4.1.1 Turbines
All seven units are horizontal shaft single jet Pelton turbines with a jet deflector and two shaft bearings. They operate at 500 rpm and have a rated capacity of 1300 kW (1750 BHP) at a net head of 320 m (1050 ft). The jet deflectors are directly driven by mechanical governors
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and the spears are driven from the governor via a time-delay dashpot assembly working against a spear closure spring.
The existing turbines are estimated to be only roughly 80% efficient.
Under a minimalist refurbishment scenario, an option exists to refurbish and upgrade only a selection of the machines. As it is rare that there is sufficient flow from the dam to operate all seven units, the long term average discharge can be met by five units, so a saving could be made by only refurbishing and upgrading five to six units. The remaining unit or units could be left as manually operated machines and operated to prevent or minimise spill at the dam at times of high inflows.
Base option:
• Decouple existing spear and deflector. Retain the existing mechanism and linkages above floor level for interpretation and heritage purposes.
• Modify the existing spear rod to remove the close spring and install a hydraulic cylinder actuator.
• Modify the deflector operating link to incorporate a small in-line hydraulic cylinder actuator.
• Hydraulic solenoid valves would allow the DC control and protection system to automatically initiate turbine shutdown. The spear closing time could be extended from 20 seconds, possibly to as much as 240 seconds to minimise pressure rise in the conduits.
• At least one complete set of new cast stainless steel bolt-on runner buckets should be initially provided, then further sets procured over the coming years until all old buckets are replaced.
• Remove damaged old pit lining and install, grout and paint a new plate steel pit lining for each turbine as necessary.
• The efficiency and energy output of the turbines would remain unchanged.
Turbine Option A:
• Includes the above base option with the addition of a new hydraulic design of nozzle end piece (which may have a replaceable nozzle seat ring) and new spear tip onto the existing nozzle body and spear shaft to provide optimised nozzle and needle angles.
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• Retention of the existing old runner bucket hydraulic design and individual bolt on buckets.
• A small increment of turbine efficiency improvement - nominally 1%, which would marginally increases the annual energy output of the turbines.
Turbine Option B:
• Based on above Option A, but instead of retaining the old runner buckets replace them with a new runner bucket hydraulic design. These could be either a new design of individually bolt-on bucket, or a new design of one-piece runner.
• The new turbine runners could be one piece castings, or machined from one piece forgings, or forged and welded, or alternatively the recently developed hooped runner could be feasible for this project. The runners could be designed and manufactured overseas, or a design could be purchased and potentially the runners manufactured within Australia (as has been done recently for a New Zealand project).
• This Option A and B together provide a larger increment of turbine efficiency improvement, nominally 6%, increasing the annual energy output of the turbines.
Turbine Option C:
• Includes a new one piece runner as per Option B, plus a completely new injector with integral internal servomotor and modern nozzle and needle design.
• Option B and C together provide the largest increment of turbine efficiency improvement, nominally 7%, increasing the annual energy output of the turbines.
4.1.2 Generators
Although it is the least cost option, if the minimalist refurbishment option is adopted, generator rewinds may need to be considered in the medium term future (within 10 years) considering the age and apparent condition of the generators.
At the time a generator rewind is scheduled, a core flux test (EL-CID and/or Full Flux) should be done to assess whether the existing core is suitable for retention. Since there is no record of any core refurbishment or replacement work on these machines, and the machines are 70 to 90 years old, the cores may need replacement; the expected life for a reinsulated winding or replacement winding would 30 to 40 years (maybe more for a complete new winding) and the core should be in a suitable condition.
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The windings of the generators have been partially rewound and repaired on a number of occasions in the past; particularly with repairs and replacement of coils in the event of lightning strikes or surges on the 11 kV system.
The generators appear to be in acceptable condition; however it is difficult to properly assess the condition of the generators as there is little condition assessment data available, as previous recording was limited. and it appears that none of this data is taken on a regular basis and trended to help identify the onset of failures/end of life. For example some IR readings have been taken in the past, usually after a repair has been completed, but no DDF or PD measurements have been taken. Previous IR readings have been variable between generators, with a very low reading obtained on one machine; machine ‘G’.
The current condition assessment is mainly based on visual inspection and the history of recent reliable operation.
The upgrade of the station earthing system in late 1990s seems to have significantly reduced the occurrences of voltage surges on the generator windings that resulted from lightning strikes and caused damage to winding coils.
However, the generator’s basic excitation system, basic electrical protection system and the retention of the autotransformers results in the generators is potentially still being subjected to excessive overvoltages under fault conditions. With four generators connected to one section of the 6.6 kV bus and the other three generators connected to the other section of the 6.6 kV bus, a number of generators would be at risk under these conditions.
Basic temperature monitoring of the windings should be added at the time a generator rewind is scheduled. It is not cost effective to add RTDs to the windings now.
Float switches should be installed in the generator pit for flood protection of the generator.
It is unknown at this time as to whether the rotor poles insulation contain any asbestos as there is very little information available on the generator manufacture and assembly. There is no listing in the Lake Margaret asbestos register; but this may be due to not being able to test a sample of the insulation. Given the date of manufacture for the generators, there may be a chance of asbestos being present. This is not a cause for immediate concern as the rotor pole insulation seems to be in good condition, therefore any asbestos that may be present is encapsulated within the insulation and vanish and is not exposed to the air. However, until it is proven that asbestos is not present, the rotor poles should be inspected on a regular basis for any signs of the pole winding insulation becoming brittle.
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4.1.3 Governors
With a minimalist refurbishment, the existing mechanical governors would no longer be used to control the turbines, but they could remain in situ to maintain their heritage value.
The station would not be required to run islanded, so the units should not require speed governors, apart from sufficient speed control to enable synchronisation and manual islanding as required. A proposed new turbine control for the existing units would separate the spear and deflector operation. A new hydraulic cylinder would directly actuate a refurbished spear. Another new hydraulic cylinder would be placed in-line in the existing deflector linkage and would directly actuate the jet deflector.
Recommendations:
• Turbines should not have unitised speed governors.
• A basic PLC speed control routine would control the turbines to enable synchronisation.
• Once on-line, the turbines could run ungoverned. Spear would be on position or load control. Deflector would be operated only fully closed or fully open (this approach has been successfully implemented for Tarraleah units 1, 2 and 3).
• Speed detection by toothed wheel or optical target would be added to the turbine shaft.
• An anticipatory overspeed protection system would shutdown the machine if speed reaches 5 or 10% above rated.
• Existing governors retained in situ for interpretation and heritage values.
4.1.4 Hydraulic power units
To provide hydraulic power to control the refurbished turbines, new hydraulic power units (HPU, or power packs) should be provided. They would not be unitised for each machine, but rather a single new hydraulic power unit would supply a stored energy pressure accumulator at each turbine unit. Alternatively, a small and simple unitised power pack located near each machine may be determined to be the optimum approach.
Due to the relatively small size of the proposed new spear actuating hydraulic cylinders, the volumes of oil to operate them would be small. This, combined with the slow closure time, results in very low oil flow rates that have to be controlled. As the system supply’s oil pressure is increased, the oil flow rates decrease. The rated system oil pressure may be an
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intermediate pressure (50 to 100 Bar) to prevent the controlled oil flow rates from becoming too low.
Recommendations:
• Turbines may each have a small simple unitised power pack, or alternatively may share a centralised hydraulic power pack.
• Each unit’s turbine and inlet valve should have a local pressure accumulator with sufficient stored energy to safely shutdown that unit.
• The majority of a centralised hydraulic power pack may be located out of sight in the power station annex to maintain the heritage aesthetic within the machine hall.
4.1.5 Excitation
The minimal cost option for the generator excitation would be to retain the existing systems. A Programmable Logic Controller (PLC) system should be implemented to provide some basic generator voltage control by driving the existing motorised excitation potentiometers.
The existing system has no under or over excitation protection therefore, under fault conditions, it is possible that the generator winding could be subject to excessive overvoltages. Even with the preset step down of excitation, in the event of a machine CB trip, overvoltages could still be an issue under some fault conditions. The existing excitation systems have no automatic voltage regulation, excitation limiters or protection (except overcurrent on the generator terminals), and rely on operator intervention to safely shut down.
4.1.6 Controls and metering
There are very few control systems for the station, with the vast majority of necessary actions being either performed or initiated by the operators.
There are desk controls for:
• circuit breaker trip/close, with the close circuit enabled by insertion of the synchronising plug into the socket for that machine
• governor raise/lower
• rectifier start/stop
• rectifier setting potentiometer
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On the generator floor there are controls for:
• governor select lever between manual, transit and automatic
• governor manual output control hand wheel
• push button or hand wheel control of the inner main inlet valves
The governor speeder motor is 110 volt DC. This motor provides adjustment of the governor speed reference over a modest range and is powered from the excitation DC supply.
The main inlet valves are all powered from a single distribution board.
A station PLC was installed in 1999 to provide some alarming functions.
The current control panels are in good order having been installed in 1970s.
In the control room, there are the following meters for each of the generators:
• kW meter, 0 to 2000 kW
• kV meter, 0 to 8 kV and a voltmeter selector switch
• generator ammeters, 3 of, 0 to 300 Amps.
• excitation ammeter, 0 to 150 Amps
• excitation voltmeter, 0 to 150 Volts
On the turbine, there is a mechanical tachometer, an oil pressure gauge on the governor unit, and a water pressure gauge, but no other metering.
There is a set of station summation meters, which includes a power factor meter that the operators must rely on to set the generator reactive loadings.
Also, there is a common set of synchronising meters, which are selected to a particular machine by a selection socket and plug system that also enables the circuit breaker close circuit.
Recommendations:
• The machines should not have unitised controls, but should all be controlled from a centralised machine PLC based control system. The PLC should have a range of inputs including:
o MIV open/closed;
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o spear position;
o deflector open/closed;
o excitation on/off;
o auxiliaries monitoring.
• The PLC should control the MIV, governor, excitation, CB and auxiliary systems and accommodate remote monitoring that could include load changes and shutdown.
• The new control system should include an operator interface and maintain the current operating location and controls.
• Machine synchronising should remain an operator function although a synch-check relay could be installed.
• The PLC could start the machine, run it up to speed and start excitation. Or each function could be performed manually.
• The machines should each have a unitised and singular relay based protection and emergency shutdown scheme.
• Remote monitoring of the machines (and station) should be implemented.
• Each machine should be fitted with an integrated power monitor, to allow for metering and control.
4.1.7 Electrical protection
The only electrical protection on the generators is a three phase, inverse time, induction disc, over current relay located in the circuit breaker panels. At this point, it is anticipated that these will remain in service.
4.1.8 Bearings
There are four bearings in total for each unit, two for the turbine and two for the generator. All are plain journal bearings with split bearing shells with white metal surfaces, running above an oil bath, and each with two oil rings to carry up lubricating oil into the bearing.
Recommendations:
• No change to the oil rings is required, as long as operator-assisted machine-starting takes place, and the operator can check oil ring operation.
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• Bearings should be fitted with temperature detection, which provides a high bearing temperature automatic shutdown.
• Monitoring of lubricating oil level would be optional, as the small quantity of oil in each bearing is held inside the one piece metal casting of the bearing lower housing, and rapid oil loss is only conceivable following unlikely catastrophic failure of the bearing housing.
• A vibration detector should be located on the turbine drive side (inboard) bearing and connect to a single channel vibration protection system that would initiate unit shutdown.
4.1.9 Turbine inlet valves
Each unit is fitted with two 15” NB turbine inlet valves in series, one outside of the machine hall and the other inside. The valves are tapered wedge gate valves with AC driven Rotork electric actuators. These valves were supplied new at the time of the penstock replacement in the 1970s and have a design pressure of 408 m (580 psi).
Current hydro-electricity industry practice would be to use a spherical valve as a turbine inlet valve in this high pressure application. These are a robust style of valve with virtually zero pressure loss through the valve when fully open. Alternatively, a high performance and high pressure butterfly valve could be used but they would introduce some pressure loss prior to the turbines which translates to a loss in generated energy. Using wedge gate valves or parallel slide valves used to be the practice in the first half of the twentieth century when this station was built. For either style of valve, hydro-electricity industry practice is for these inlet valves to provide protection for the turbine and be capable of automatically isolating the turbine in the event that the turbine or governor has lost control. To achieve this, the valve should automatically close in an emergency using a reliable form of power, typically using either a counter weight, or stored hydraulic energy from a pressure accumulator, or the available stored hydraulic energy in the penstock pressure water.
The existing electric AC motor driven actuators are not regarded as adequate for secure emergency valve closure, because in the event that they need to be closed following a turbine load rejection, this is when AC power supplies to the station may be lost.
The lowest cost option is to retain these gate valves for ongoing use with the existing turbines, but to modify the inner valve by removing the Rotork electric actuator and installing an oil hydraulic cylinder actuator directly operating the valve stem. The hydraulic power
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would come from a centralised new hydraulic power unit also used for turbine spear and deflector control. The detailed design and implementation would need to ensure that the issue of valve stem breakages was not reintroduced.
The valve closure should be controlled at a rate slower than the turbine spear or needle, so that when the valve and spear are closing simultaneously the spear would be controlling the water flow. The preliminary hydraulic transient modelling completed indicates that the turbine spear closure may need to be slowed down to the order of 240 seconds and, in this case, the turbine inlet valve closure time would be in the order of 260 to 300 seconds.
Recommendations:
• Retain existing inner gate valve but modify to include a hydraulic cylinder actuator.
• Each unit’s turbine and inlet valve should have a local pressure accumulator with sufficient stored energy to safely shutdown that unit.
• A hydraulic solenoid valve would allow the DC control and protection system to automatically initiate valve closure.
The turbine inlet valves may each have a small simple unitised power pack, or alternatively may share a centralised hydraulic power pack. The majority of a centralised hydraulic power pack may be located out of sight in the power station annex to maintain the heritage aesthetic within the machine hall.
4.2 Station services
4.2.1 AC power
The AC system had been recently upgraded (1999) so no significant work would be required for a redevelopment option. The failure of one of the station’s service transformers after only a few years of service is the only issue of concern. The other transformer seems to have given reliable service and, even in the event that it fails, the station can maintain operation with only one station service transformer while a replacement transformer is obtained.
4.2.2 DC power
The DC system was upgraded in 1999, therefore no further upgrade work would be required with the only consideration being for the provision of additional circuits to cope with any upgrade/ replacement work as identified in other sections of this report.
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4.2.3 Crane
The modern 5 tonne auxiliary chain hoist should be maintained to enable it to be used for small lifts, such as during routine maintenance work if the generating units are retained in service and upgraded. It would not be possible to return the original crane to its original 15 tonne rating, or to provide a new crane of equal or greater rating, without completion of a structural analysis. Strengthening and stiffening the main crane along-building support beams that support the crane long-travel rails may be required. To substantially increase the lifting capacity it is likely that additional columns could be required from machine bay floor level.
Recommendations:
• That the overhead crane be retained in service using its 5 tonne auxiliary hoist.
• That the 15 tonne crane be returned to service, or a new crane is provided, if required for heavy lifts (eg generator rewinds).
4.2.4 Station ventilation
The existing generators are open framed and rely on natural circulation of air within the machine hall for cooling, through open doors and windows, and through roof passive ventilators.
If the station is operated unattended overnight, or at other times with the existing or upgraded old generators, then the building would need to be securely closed up which may inhibit natural ventilation and cooling of the generators. In this case, additional ventilation may be required. This could be via additional natural ventilation, or addition of a forced air supply and/or exhaust through the machine hall walls or roof. Significant changes to the building would require approval under the HCHA 1995 and a Heritage Impact Assessment.
4.3 Tailrace The only option is to repair or replace the majority of the pit lining metalwork. This would involve fitting new steel plates and anchoring them into the existing concrete (if it has sufficient residual strength), then grouting behind the new pit lining to fill all voids between it and the original concrete.
The remainder of the tailrace concrete requires preparation and shotcreting.
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4.4 Switchgear While the generator CBs are bulk oil design and represent a fire risk, they have a history of reliable operation except for CB ‘G’. The refurbishment option would be to retain the existing CBs except install a replacement for the unreliable CB ‘G’.
The autotransformers and the 6.6 kV bus tie CBs are an older design with essentially good operation reliability, however they do pose a higher fire risk. These CBs could be retained for the short to medium term operation (5 to 10 years) before replacement should be considered.
Currently, there is only one exit from the switchgear rooms. In order to address the fire risk to operators and other personnel on site from the bulk oil CBs, it is recommended that an alternative escape be installed. The rooms are located above the control room and beside the transformer yard, so the only possible second exit would be to install a doorway in the end wall of the switchgear room containing the transformer and bus-tie CBs, and exit platform and ladders/stairway above the workshops down to ground level.
Local operation of the CBs, in front of the switchgear panel, is a concern for the safety of the operator.
Another measure to address the fire risk associated with the circuit breakers is to install fire suppression within each CB cubicle; such as a system using Pyrogen condensed aerosol canisters or similar product, to limit the risk of fire spreading to other cubicles. The initiation of these systems can be isolated for individual cubicles to allow an operator or technician to safely work on any one of the cubicles for maintenance or repairs.
There is another potential safety risk in this area, as the outside wall of the switchgear room containing the generator and station services CBs facing the autotransformers has windows. This wall does not meet the minimum ‘fire rating’ requirements for oil-filled transformer installations as per the current Australian Standards. It is recommended that the windows in this wall be bricked in to provide better protection in the event of a transformer fire, particularly if a new single large transformer is to be installed.
If the autotransformers are to be replaced, then this could be an opportunity to replace all of the old transformer and bus-tie CBs as well. A rearrangement of the 6.6 kV bus could be done with a new single transformer and single outgoing CB as a cost effective alternative.
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4.5 Transformers Transformer ‘B’ is already out of service and, therefore, replacement in the near future needs to be considered for the station to maintain full operation. The alternative is to leave Transformer ‘B’ out of service and make do with the three transformers remaining, as this would handle the station output under most circumstances. This would have a higher risk of significant reduction in station output and lost energy production if one of the three transformers failed.
Transformers ‘A’ and ‘C’ are aging and, therefore replacement, should be considered for the short to medium future (5 to 10 years). In the meantime, regular oil analysis would be required to monitor these transformers in service.
Autotransformers are not appropriate as generator transformers, they do not provide proper isolation from the HV (11 kV) system. This should be taken into consideration for the transformer replacements. The recommendation is that if only one of the existing transformers is to be replaced, the new transformer should be an autotransformer to fit in with the existing bus and protection arrangement. However, if all four transformers are to be replaced then the replacement transformer(s) should be two winding transformers.
The replacement could include either four, two or a single transformer. The weight of a single 12 MVA transformer is of the order of about 30 tonnes, so transport access to site and crane capacity would need to be considered..
Physically a single 12 MVA transformer can fit within the existing transformer yard, however the structure of the transformer yard should be checked to see that it can handle the higher point loads of a single transformer and the oil containment system would have to be upgraded to handle the higher oil quantity associated with the larger transformer.
4.6 Powerhouse viewing platform In September of 2006, JMG was commissioned by Hydro Tasmania to investigate redevelopment of Lake Margaret as a tourist facility. In their initial pre-feasibility report, they specifically looked at providing viewing platforms at the powerhouse (Ref. 10). JMG looked at two options and provided costs for both:
• The station is closed as an operating station and the public could enter through the northern part of the building. Ramps, stairways, handrails, lighting etc would be needed to meet the requirements of the BCA. Estimated cost $36K.
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• The station remains operational with much of the works being viewed. This would involve a ramp and walkway, (probably on the west wall). The viewing enclosure was nominally chosen as 10 m x 3 m, have a roof, guard railing and glazed walling to view the power station. Estimated to cost $1.0 m
JMG provided these estimates on the basis that the scheme would be developed as a tourist operation. Should the station remain in service, and not be a dedicated tourist facility, it would still be possible for tourists to observe the power station in operation. The following is assumed for this arrangement:
• approvals for the works are obtained under the HCHA 1995 and Heritage Impact Assessments are completed;
• tourists are supervised;
• the southern entrance to the power station would be the viewing area. This area could be glazed, for noise reduction, and still allowed to open and close for operational purposes;
• interpretative material is supplied and installed near the car park.
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5. OPTION 2 - NEW MACHINE WITH A SIMILAR CAPACITY TO THE EXISTING MACHINES
Option 2 is that a new machine, nominally 10 MW, be installed in a new powerhouse or annex located at the present location of the penstock distributor, between the existing station and the Yolande River. A new powerhouse could be annexed to the existing station so that only the minimum working space would be needed next to the machine, and other workshop, office and amenities facilities could continue to be provided in the existing building. This option also involves the completion of the headworks upgrades discussed in Section 6.
Multiple machines have been considered and could be installed in the existing powerhouse. This option is not preferred due to the increased costs.
A discussion of possible options for the location of a new powerhouse is contained within the Conservation Management Plan by Paul Davies (Ref. 5). However, a detailed Heritage Impact Assessment would also be required.
A new power station is likely to take until July 2009 to commission due to equipment procurement lead times.
The economic return estimated for this option has factored in qualifying for a zero Mandated Renewable Energy Target (MRET) baseline and associated RECs. Under the current rules for RECs, for the Lake Margaret Power Station to become eligible for RECs for all of its production it would need to be shutdown for three years, and at least 50% of the cost of the same station built on a greenfield site be reinvested into a redevelopment. This would require the station to remain decommissioned until July 1, 2009.
This construction period of the new hilltop pipeline will be targeted during summer months. Lead times on a new turbine generator set are about 18 months. Hence power station construction would start late 2008 with machine installation and commissioning during the first half of 2009.
5.1 New generating sets
5.1.1 Increased generator size
An Investigation was carried out on larger generator sizes. A larger size could enable the Lake Margaret Power Station to be run as a peaking plant.
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The size of the hilltop pipeline constrains the maximum allowable flows or there is a risk of negative pressure in the hilltop pipeline, which could cause significant damage. With a significantly larger diameter hilltop pipeline the maximum size is restricted by headloss in the existing penstock. This limits generator size to approximately 20 MW.
Increasing the size of the current hilltop pipeline significantly was found to be economically unviable.
5.1.2 Machine type
Possibilities considered included a single 10 MW Pelton or Francis turbine unit, or three by 3.3 MW Pelton units. Both horizontal shaft and vertical shaft installations are possible.
The discharge and head are at the limit of a standard Francis turbine range, or beyond it for some manufacturers, but a Francis turbine could operate at a higher speed and therefore the turbine and generator can be physically smaller, therefore potentially cheaper. Francis turbines also offer slightly higher peak efficiency, and can utilise slightly larger net head, so can generate more energy than a similarly rated Pelton turbine set.
The drawback for high head Francis turbines with a low specific speed (60 to 70 kWm at Lake Margaret depending on unit speed) is that following load rejection, their runners quickly throttle the flow due to centrifugal action as they accelerate towards runaway speed, and this flow reduction is be independent of the guide vane closure time. This has implications for penstock pressure rise. The existing penstock can accept little pressure rise as one section of it has a maximum allowable head close to the maximum static head profile, and the existing old turbine components, if retained in service, can accept very little pressure rise above maximum static head.
Preliminary budget prices for Francis turbine sets for this application has placed them more expensive than Pelton turbine sets, in part due to the fact that the Francis units are at or beyond manufacturer’s standard small turbine ranges.
These above two points have eliminated Francis turbines from this particular power station application.
5.1.3 New generating set(s) in the old powerhouse
Installation of a new generating set(s) in the old powerhouse has been considered. Existing station services are discussed in Section 4.2. Hydro Tasmania’s internal heritage consultants have indicated that it may be acceptable to remove two or even three of the original old
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generating sets to make way for one or more new units. Issues with the existing building that impact on the installation of new machines include:
• existing cranage limited;
• poor access for large plant or any vehicles into station building;
• all large loads may require lifting by a mobile crane through a dismantled end wall or roof of the existing building extension;
• risks are associated with removing part of the roof or end wall during installation due to poor structural strength of old building extension;
• unknown existing foundation strength or details. No reinforcement details are available, and it is suspected that the existing machine hall foundations may not be on rock but rather partly on hand prepared rubble or fill;
• poor condition of the existing turbine pit liners and foundation steelwork;
• poor condition of the tailrace concrete lining;
• heritage issues impacting on extent of works.
An arrangement of a single 10 MW horizontal shaft Pelton unit has been considered inside the existing building, in place of existing units ‘E’, ‘F’ and ‘G’. This would likely be a two jet unit operating at 428.6 or 500 rpm, although at least one manufacturer is capable of supplying a three jet 600 rpm horizontal unit. The turbine would be directly coupled to the generator, and it would be two bearing unit with the runner overhung on the generator shaft.
The estimated total weight of the single generator of about 11 MVA would be of the order of 40 to 50 tonnes. Even if the generator was transported in smaller components and assembled on site, a complete stator or rotor would still weigh in the order of 20 tonnes, exceeding the capacity of the existing crane rating. Transporting the generator to site as smaller components would increase the installation time and costs over that for a generator supplied as a single complete unit.
For a single 10 MW machine, there could be issues with maintenance/installation access available for the generator, particularly if it is a horizontal unit which would require greater floor area for assembly of the generator on site or pulling the generator apart for any major maintenance work. Considerable horizontal axial distance is required to insert or extract the generator rotor. This could require modification to the internal structure of the power station depending on machine location and layout.
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An alternative arrangement has considered the option of three horizontal shaft Pelton units, each of nominally 3.3 MW. These would likely be two jet Pelton turbines operating at 750 rpm. The turbine would be directly coupled to the generator, and they would be two bearing units with the runner overhung on the generator shaft. These smaller units have the advantage of fitting roughly within the footprint of the existing old units, and so could be arranged directly in place of existing units ‘E’, ‘F’ and ‘G’. It is believed that the heaviest lift, the complete generator, would be of the order of at least 18 tonnes which exceeds the existing crane capability and so would require mobile crane access.
Both 10 MW and 3.3 MW options would require repair work to the tailrace channel.
Both the single 10 MW option and the three 3.3 MW option would be supplied complete with new turbine inlet valve, turbine, generator, turbine governor, integral controls, hydraulic power unit, generator excitation and AVR, generator protection, and generator cooling system.
Both options require modification of the penstock distributor piping to provide a larger pipe or pipes through the station wall and to the new units.
Considerations:
• Installation of three 3.3 MW Pelton units within the existing building minimises civil and structural changes within the station building and reduces risks associated with lifting and handling.
• The electrical and mechanical equipment purchase and installation costs for three 3.3 MW units are however about up to 40% to 60% higher than the larger single 10 MW unit.
• The electrical and mechanical equipment purchase and installation cost saving for the single 10 MW unit in the existing powerhouse may compensate for the increased foundation costs, and lifting and handling costs.
• Both new machine options nominally increase the turbine efficiency to about a peak of 90%.
5.1.3.1 Crane
The modern 5 tonne auxiliary chain hoist should be maintained to enable it to be used for small lifts. If a new generating unit was installed within the existing building then the overhead crane could be used for routine small lifts such as turbine runner removal for
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inspection and NDT. It is estimated that the existing turbine runners complete with buckets and shaft weigh in the order of 3 tonnes.
It would not be possible to return the original crane to its original 15 tonne rating, or to provide a new crane of equal or greater rating, without completion of a structural analysis. Strengthening and stiffening the main crane along-building support beams that support the crane long-travel rails may be required. To substantially increase the lifting capacity, additional columns could be required from machine bay floor level.
If one or more new generating sets are installed within the station’s machine hall, then all heavy lifts would have to be undertaken by a large mobile crane. The crane would gain access either by removing part of the building roofing, or removing part, or all, of the end wall. But with some structural concerns about the adequacy of the existing building superstructure, the option of partly dismantling the roof or end wall for mobile crane access is not recommended unless the building structure is strengthened.
5.1.4 New generating set in a new building
Due to the lack of space available between the existing station building and the river, together with the arrangement of the existing penstock, a vertical shaft generating set is favoured. The turbine is recommended to be a Pelton for the reasons presented in Section 5.1.2 above.
The turbine is likely to be a four or six jet vertical shaft Pelton, operating at 600 or 750 rpm. It would be a two bearing unit with the runner overhung on the generator shaft.
If a new building was built and styled as another annex to the existing building, then the existing external windows affected by a new building can be retained, and used for visitors in the old machine hall to look through at the new generating set. The image of the arched windows could be replicated by similar shaped recesses in the new outer wall of the new building. The preferred site options for a new station building are outlined in the Paul Davies Conservation Management Plan (Ref. 5) and are to be considered in future development plans. All new building work would be subject to a Heritage Impact Assessment and approvals through the HCHA 1995.
Preliminary excavation and investigation of the ground in the location of a new building, but on the riverside of the existing penstock distributor, has revealed what appears to be relatively loose fill for 4 m below the surface until harder conditions were encountered. As this fill would require excavation to make way for foundations for a new building, it readily
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enables the turbine setting height to be lowered to maximise the net head available to the turbine.
A previous flood study, associated with dam-break scenarios, indicates only very limited river level rise during a flood (with no dam-break). This also enables the turbine setting level to be lowered.
A feasible preliminary concept layout of a new station building has been prepared (see Volume 2, Appendix 14). The current cost estimates include provision for a station crane capable of lifting the heaviest machine component. This was included, rather than a mobile crane, due primarily to weather considerations, where the roof would be required to be off for extended periods during major works. This could be reviewed during detailed design as a cost saving measure.
For routine maintenance, such as turbine runner removal for inspection and NDT, lifts up to nominally 3 tonne could be undertaken using a monorail hoist.
A new building would require a number of station services that may be extended from those in the existing old station building or, as the future use of the existing power station building is uncertain, these station services may be independently supplied within a new building. These are station services such as AC and DC electric power supplies, phone communications, fire detection and intruder detection. Amenities such as an office, workshop, mess room and toilet are not required as long as they continue to be available in the old power station building. The new building would require ventilation, and fire protection equipment.
It is feasible to run the power cables from the new generator in a duct below ground level to a new site for the transformer and outdoor switchgear; the likely location of the yard would be a site just on the other side of the car park at the southern end of the existing power station. A new span would be required to pick up the transmission line.
The site earthing would be extended to pick up the reo bars within the new building concrete foundations and the exposed metalwork within the building, provide a grading ring around the new building, and earthing conductors to be installed in the power cable duct to connect the transformer yard earthing together with the new building.
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Considerations:
• The preferred site for a new power station is immediately adjacent to the existing building on the river side, out of view when approaching the power station via the access road. This would maximise the physical and aesthetic connection between the old building and new building or annex, and best enable sharing of some facilities between the two buildings.
• The preferred generating set type and arrangement is a vertical shaft Pelton turbine directly driving a synchronous generator, producing nominally 10 MW from a flow of 3.9 m3/s at a net head of 300 m. The final ratings would be optimised during detailed design and implementation.
• This new machine would increase turbine efficiency to a peak of about 90% or marginally higher. It also allows setting level of turbine to be lowered which increases the net head available across the turbine. This would increase the annual energy output of the turbine.
Recommendation:
• It is recommended that if a new machine is purchased that it be a vertical Pelton nominally 10 MW machine, installed in a new powerhouse or annex located at the present location of the penstock distributor, between the existing station and the Yolande River.
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6. COMPONENTS COMMON TO BOTH OPTIONS
6.1 Dam works Dam safety analysis has concluded that the following works are required on Lake Margaret Dam:
• crest raising (left-hand dam only) to protect the outlet works;
• treatment of leaking construction joints in the concrete dam.
Crest raising (left-hand dam only) is required to increase the spillway capacity. This work should proceed and is considered to be required regardless of whether redevelopment occurs. Therefore, the cost of crest raising does not need to be included in this analysis.
The estimated cost for treatment of leaking construction joints has been included within the redevelopment options. It is proposed to complete this work from the upstream face. Preparation of the upstream face could be by water blasting to remove any deletious material. Some areas would be square cut and scabbled to achieve a minimum depth. The areas where there are large voids could be backfilled with a cementitious product. The remaining areas could be rendered. This work is required primarily to minimise risk of corrosion of the pre-stressing cables located within the dam.
6.2 Outlet works at dam The existing arrangement incorporates two outlet conduits, each with its own bulkhead gate, trash screens and outlet isolating gate valve (see Figure 6-1). Currently the existing woodstave hilltop pipe is on the 1938 alignment and connected to one of these outlets. The other outlet is normally not used.
It is proposed to take one outlet out of service. The new hilltop pipeline is proposed to follow the original 1914 alignment between the dam and where the current tramway and pipeline cross over. It is proposed to connect to the original 1914 outlet conduit at the dam. This conduit and associated gates, screens and valves could be repaired, refurbished or replaced as described in more detail below. The other outlet conduit could be left in its current original condition (see Figure 6-2).
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Figure 6-1 Existing dam outlet arrangement
Two outlet Dam wall gate valves Interconnecting butterfly valve (normally closed)
Existing woodstave pipe (1938 alignment)
Sluice valve
Two bulkhead Two sets of gates (stoplogs) screens
Figure 6-2 Future dam outlet arrangement
Original outlet Dam wall gate valve
Air stand pipe
New hilltop pipe on 1914 alignment
Interconnecting butterfly valve New automatic butterfly guard valve and normally closed small bypass valve One bulkhead Screen gate (stoplog)
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6.2.1 Bulkhead gates and screens
The existing bulkhead gates are cast iron, original, have no seal and are of unknown casting quality. They have proved adequate over the years for their very infrequent use, but are of unknown design, strength or quality. Currently, the seal is between the cast iron gate and a cast iron guide and seat in the dam wall providing an adequate but not highly effective seal. Extensive works could be required on the dam and conduits during redevelopment with the bulkheads in place and requiring an effective seal to allow dewatering. With the lake full and spilling, it is recommended that the existing bulkhead gates undergo a thorough inspection and detailed design review to ensure they are adequate and safe. The existing bulkheads may require modification or repair, or new bulkheads may need to be fabricated.
For the conduit that is no longer used, the bulkhead gate would be permanently in place and underwater. In this case, a new bulkhead (or stoplog) manufactured from reinforced concrete may be more durable and corrosion resistant. This bulkhead can incorporate a resilient seal to ensure it effectively seals and minimises or eliminates continuous leakage.
The dam outlet originally incorporated imbedded bypass pipes and valves to allow flooding downstream of the bulkheads and equalising of pressure before their removal, but these are understood to be no longer in service. The new bulkheads should incorporate a bypass valve or other downstream flooding device to allow pressure equalisation before opening.
The cast iron bulkhead guides in the dam wall should be inspected and repaired underwater as necessary. They may require to be cleaned up and all holes filled, or faced with stainless steel angle bolted to the dam wall and grouted to seal leakage between it and the original seal or dam wall. This work would have to be undertaken by a qualified diver.
All dam infrastructure has a very high heritage significance. Management guidelines and minimum requirements are outlined in the Conservation Management Plan (Ref. 5). Careful consideration must be given to recording items that are removed and how they are reused for interpretation purposes.
The screens at the inlet to the two conduits can be retained as is. The set in the unused outlet can be removed and stored above water level, and retained as spares.
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It is recommended that the existing manual hoist used for the bulkheads and screens be removed from service, and the hoisting be undertaken by a new electric chain hoist hung from a modified structure above the in service bulkheads and screens on the dam wall. This would remove the need for manual winch operation and allow the hoist operator to observe the bulkhead or screen being lifted or lowered. The existing manual hoist and its hoist house should be preserved and retained in situ for their heritage value.
Recommendations: • The existing bulkhead gates undergo a thorough inspection and detailed design review to ensure they are adequate and safe.
• The cast iron bulkhead guides in the dam wall should be inspected underwater by a diver and repaired underwater as necessary.
• Repair and refurbish the existing bulkheads, or fabricate one new bulkhead gate with seals for the out of service conduit, or fabricate two new bulkheads if necessary. If removed they need to be recorded and can be used for interpretation purposes.
• A new chain hoist be provided for lifting the in service bulkhead and screens.
6.2.2 Outlet valves
There is an outlet isolation valve on the downstream end of each of the two through dam conduits. One outlet valve and conduit used to connect directly onto the original 1914 woodstave hilltop pipe alignment, but in 1938 the replacement hilltop pipe was installed on a new alignment beside the original, and this still connects directly onto the other outlet valve and conduit.
These two 1200 mm NB gate valves were electrically actuated many years ago, but are now manually operated. An operator takes approximately 1.5 hours to travel to the dam and close a valve if required for isolation or an emergency (if the operator is already at the power station and is in a position to leave it). It is normal practice for a dam outlet such as this to incorporate a gate or valve that can be initiated automatically, or remotely, to close into a flow that may be due to a loss of control downstream or a burst hilltop pipeline.
As one dam outlet conduit could be removed from service, its outlet gate valve can be retained in its current condition and left open or partly open to drain leakage water.
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The other existing outlet gate valve could be automated and be fitted with a proprietary electric actuator, for example, with a Rotork style actuator that have recently been fitted to other similar sized remote location valves within Hydro Tasmania. The valves are reported as still operating well, but no internal inspection or maintenance has been undertaken in recent memory. The valves have proved adequate over the years for their very infrequent use, but are of unknown design, strength or quality. Any refurbishment would have to be undertaken in situ. Due to their unknown internal condition this is a high risk undertaking. This automated valve would be dependant on an auto-start electric generator at the dam as its only power supply, and rely on it for automatic and unattended emergency closing.
It is recommended that a new automatic guard valve be installed downstream of the gate valve before the beginning of the new hilltop pipeline. It is recommended that this new automatic guard valve be a heavy duty butterfly valve designed for guard duty and closing off pipeline discharge, that it be closed automatically by the stored energy in a counter weight, and opened by a self contained small on-board hydraulic power pack. As AC power is not required for closing, and as opening speed is not critical and can be slow, this reduces the power rating, availability and fuel storage requirements for a portable electric generator at the dam. This new guard valve may be identical to the proposed new hilltop guard valve.
It is recommended that the existing gate valve in the operating conduit be stripped, the valve’s bonnet and gate could be removed and a cover plate fitted to allow the valve body to remain as part of the conduit. For security and dam safety, this remaining cast iron valve body and any remaining pipe upstream of the new guard valve should be encased in a layer of reinforced concrete to eliminate any possibility of leakage or burst. To reduce internal water friction, the remaining valve gate slot may be filled with concrete or grout.
The new guard valve would require a small bore bypass valve to enable controlled and safe filling of the downstream hilltop pipeline prior to opening the guard valve. This bypass would be nominally 100 to 150 mm NB and include a manually operated valve, and require an off take from the conduit on either side of the guard valve.
It is recommended that the trip actuation of the automatic valve be available remotely from the power station, or from System Control if the station is de-manned and remote controlled. Also, automatic local tripping of the valve should be initiated by an over velocity detection device. This may consist of a differential pressure measurement across the intake bell- mouth, for example, using the existing but cleaned and rehabilitated intake well drain pipe as
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its upstream connection. Alternatively, the over velocity could be detected via a compact insertion type magnetic or acoustic flow meter of relatively low accuracy. As the burst pipe discharge may not be that much greater than the normal maximum pipe flow the overvelocity detection may be improved by transmitting the station summation load to the dam, then from this automatically estimating a station discharge for comparison. If there is a gross mismatch over a preset time interval, then this could be interpreted as hilltop pipe or penstock burst and it would be possible for the outlet valve to be tripped closed.
Recommendations: • Retain one existing cast iron gate valve in current condition on the unused outlet conduit.
• Provide one new automatic counterweight close butterfly guard valve on the downstream end of the in-service outlet conduit, for dam safety and hilltop pipe protection. It is recommended that this valve be identical to the new hilltop guard valve proposed for penstock protection.
• Provide a smaller bore bypass around the guard valve for filling of the hilltop pipe.
• Provide an over velocity detection and trip scheme to automatically trip the new guard valve.
6.2.3 Interconnecting valve
The interconnecting valve is a special 42” NB valve designed to fit in a 48” NB interconnecting pipe, and is almost a wafer type of connection with the valve sandwiched between the two flanges on the pipe branches. Its flange face to face dimension is only 150 mm. It is reported to not seal well and leak when closed, preventing an effective isolation between conduits.
This interconnection could be removed between the conduit in service and the conduit removed from service. The interconnecting valve can remain in place in current condition together with the cast iron tee piece on the out of service conduit, downstream of the retained outlet gate valve.
Recommendation: • It is recommended that the interconnecting valve be retained in place and in current condition together with the cast iron tee piece on the out of service conduit.
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6.2.4 Sluice valve
The existing 500 mm NB sluice valve is on the end of the right-hand (looking downstream) through-dam conduit, and can be used for dam dewatering. The current valve and piping are unsuitable for large flows, and discharge in an unsuitable location. The valve and dewatering discharge are normally not used and have not been used in recent memory.
If in the future a dam dewatering outlet is required, or if a constant riparian outflow from the dam is ever required, then the out of service dam outlet conduit can be used, with the future addition of valves and piping to take the water out of the rock cutting and towards the river.
Recommendation: • Remove the sluice valve and discharge piping.
6.2.5 Air valves
There are no existing air valves, but rather a stand pipe on each conduit downstream of the isolating gate valves. These standpipes are badly corroded and not fit for future service, and the air pipe on the dam outlet conduit that would be retained in service should be removed.
As a new automatic guard valve is recommended to be installed, then an air inlet and air release should be fitted to the top of the conduit immediately downstream of this guard valve. A new air stand pipe would be fitted to a connection downstream of the guard valve, with the top of the pipe above maximum dam water level. This would protect the hilltop pipe against vacuum collapse and release air during pipe filling.
On the dam outlet conduit removed from service, the existing air stand pipe could be retained in current condition to illustrate the original dam outlet arrangement. As it would no longer contain water its corrosion should be reduced, and it could be capped at its upper end to keep out rain.
Recommendations: • Remove old air pipe on in-service conduit.
• Install a new air stand pipe downstream of the new guard valve.
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6.2.6 Outlet conduits
Once the bulkhead gates and their guides have been replaced or rehabilitated to enable an effective seal and isolation, then the downstream through-dam conduits can be dewatered and inspected after removal of downstream pipe work. These two 48” NB conduits through the dam have cast iron liners, and minor water leakage between the liners and dam concrete has been observed.
In conjunction with grouting repairs to the rest of the dam, it is recommended that the area outside both the through-dam conduits be pressure grouted to fill any voids and stop water leakage.
It is recommended that the liner in the conduit to be retained in service should be cleaned and its surfaces inspected, then repaired and repainted both internally and externally where accessible. The out of service conduit could be left drained so its liner internal condition is not critical.
The two 12” NB sludge drain pipes from the upstream foot of the dam are no longer used, and it is recommended that their valves be removed and the pipes blanked off. Ideally they should have cover plates fitted by a diver over their upstream end, if accessible. It is recommended that the two 6” drain pipes from the intake wells be cleaned out and repaired if necessary, and their isolation valves replaced if poor condition of the existing valves warrants it.
Recommendations: • Grout between cast iron liner and concrete for each of the two outlet conduits.
• Remove two 12” NB sludge drain valves and blank off the exposed upstream ends of the pipes, or grout up and seal off the pipes.
• Clean out the two 6” NB drain pipes and replace their isolation valves if necessary.
6.2.7 Power supplies, controls and communications
Currently the dam area is without any type of power supply. Given this, there is also currently no control and communications between the dam and station.
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Given the above recommendations, a power supply, controls and communications to the station would be required.
Recommendations: • A remote area power system be installed.
• A generator supplies a small AC reticulation system supplying light & power and valve motive power. Also, a supply to new bulkhead and screen hoists.
• The standby battery supplies the tripping supply to the automated shutoff device and communications equipment to the station. The standby battery would be capable of being charged from the 240V AC system as well as the solar array.
• Communication between the dam and station could be used to monitor the dam from the station and remotely trip the automatic shutoff device.
• The generator should be located within the current building structure at the dam.
6.3 Replacement of hilltop pipeline
6.3.1 Removal of existing woodstave pipeline
Any redevelopment option requires replacement of the current woodstave pipeline. Hydro Tasmania have considered all prudent and feasible options for retaining the existing pipeline, however, unfortunately no practicable option exists.
Lining the existing hilltop pipeline with a sleeve was considered by Hydro Tasmania and Sinclair Knight Merz (SKM) as an alternative to constructing a new pipeline. SKM (Ref. 6) stated that:
The lining would have to be structural to carry the water pressure and span between supports with the water weight, as the woodstave pipe would dry out and lose even the marginal structural properties it has and not be able to support the lining. The deteriorating woodstaves would result in unsuitable bearing support at the pipe pedestals, and the pipe supports would need refurbishing. Also, the dried out woodstaves would crumple and fall away in an untidy fashion that is not likely to preserve the heritage value of the pipeline.
It was concluded that the issues described above result in such a solution being very costly, with uncertain success. The result is also unlikely to preserve the heritage value of the pipeline.
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A number of options have been considered for the removal and salvage of the old pipeline. The two favoured options are to:
• cut pipe into short sections, retaining by netting and lift by helicopter to a laydown area for dismantling;
• cut bands, dismantle staves and store on the pipeline route until subsequent removal by trolley during new pipeline construction phase.
On the basis that a trolley system would be installed to construct the replacement woodstave pipe the preferred option is to dismantle staves and stockpile on site. Materials can then be removed from site as part of the construction sequence of the replacement pipeline.
6.3.2 New pipeline alignment
Two different hilltop pipeline alignments have been used at Lake Margaret. The first pipeline was built in 1914, when the original scheme was constructed, and the second in 1938. It was essential to maintain operation of the power station during construction of the 1938 pipeline and hence to create a second alignment. There is no requirement to maintain operation of the power station during this redevelopment, hence there is flexibility in the choice of pipeline routes.
The most practical alignment for a new pipeline is to use the approximate 1938 alignment, between the hilltop valve and the existing crossover of pipeline and tramway, and the original 1914 alignment between the existing crossover and the dam, avoiding the alignment of the sections identified for preservation. A walking track would still be provided to the dam.
The benefits of this alignment are:
• pedestrian access would remain on the uphill side of the pipeline and there would be no need to pass under the proposed pipeline;
• straighter and shorter alignment reducing construction costs and pipeline losses during operation.
6.3.3 Pipeline material and installation method
Options considered for replacing the current woodstave pipe included steel, glass reinforced plastic (GRP) and woodstave.
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The following construction process has been assumed for the purpose of budget estimates of the construction regardless of whether steel, GRP or woodstave is used:
• The existing woodstave pipeline will be dismantled, apart from the three sections designated for heritage interpretation. Materials could be bundled and stored adjacent to the pipeline.
• New pipeline sections could be taken to the hilltop via the haulageway. The haulageway would need to be upgraded to 2.0 tonnes SWL for steel pipes of 9.0 m maximum length.
• Pipeline support construction could start from the downstream end and pipeline installation could start at the dam outlet, both using a permanently installed rail system. Pipework and other materials could be transported to the point of construction via the rail system. The materials from the old pipeline could be taken back to the hilltop via the rail system as construction proceeds.
On this basis the existing tramway would no longer be required but would remain in place up to the existing crossover of pipeline and tramway. Beyond this, it is intended to restore foot access to the dam partially along the 1938 pipeline alignment and then incorporated as part of the new pipeline support structures where bridge access is required.
It is possible that a lower cost construction method could be employed for a replacement woodstave pipeline to capitalise on the fact that woodstave has greater construction flexibility with regard to bends and the fact that materials can be manhandled. However, consideration must be given to long tem maintenance access in line with modern day Occupational Health and Safety requirements. The trolley system described above is able to provide safe access for maintenance.
The total costs are generally similar for all the three pipeline material options.
The design life of the above ground GRP pipe beyond 30 years is unknown, especially in this harsh environment. GRP is more susceptible to mechanical damage during construction or in service than either steel or timber. It is combustible (the same as timber) and can suffer from fire damage. For these reasons, in view of the fact that there is no cost advantage, the GRP option has been discounted.
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The woodstave pipeline option, similar to GRP, is susceptible to fire damage. However, it should be noted that the current pipeline has been burnt in one section but still survived many more years. The design life of woodstave is generally accepted to be 40 years, with our local and international experience being that they generally last longer. Maintenance costs on woodstaves should be minimal for the first 20 years but would then rise in subsequent years.
The steel pipe’s main advantage is that it is a lot more robust than timber and GRP and has a design life of 80 years. Maintenance costs are minimal. Internal painting would be required at around 40 years. Steel pipe is heavy to handle during construction. However, steel sections up to 9 m can be handled by the haulageway and rail trolley system as proposed. Refer to proposed pipe support details drawing in the Volume 2, Appendix 15.
On balance, a replacement woodstave pipeline is considered to be higher risk than steel due to fire risk, and potentially has a less predictable service life. However, timber is still a suitable material and could be considered if the cost is competitive with steel. It also is likely to be viewed favourably when considering the heritage values of the site. The lowest price obtained for a woodstave was slightly higher than steel but close enough to be considered viable at this stage, dependent on firm tender prices. This price was based on North American supplied Yellow Cedar, which is used in North America in pipe and barrel applications where treated timber is not acceptable. Consideration has been given to the use of King Billy pine and enquiries have been made with Forestry Tasmania, but, due to limited quantities and price, it is not considered a viable option. Forestry Tasmania (Volume 2, Appendix 6) has identified some other Australian timbers that could be suitable for a woodstave pipeline. An analysis of price and availability of these timbers has not been completed.
6.3.4 Pipeline operation
A hydraulic transient analysis of the hilltop pipeline has been completed. See Volume 2, Appendix 16 for details of the analysis.
The operating restrictions recommended below, as a result of the transient analysis, could be reviewed after optimisation of the hilltop pipeline diameter.
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Woodstave pipeline Negative pressures become a concern for the woodstave pipeline when operated at full gate and the reservoir level is more than 2 m below FSL. This case assumes that the pipe has a relatively high roughness and is in a slimed condition. This situation should be avoided, and it is recommended that if a new woodstave pipeline is used then the following should be considered:
• Regular cleaning of the internal surface of the pipeline to reduce its roughness and prevent excessive negative pressure particularly at low storage levels.
• Implement operating rules that prevent full gate operation when the reservoir is at low storage levels
• Ensure that the anti-vacuum valves, near the HTV, are fully operational and are of sufficient capacity
Steel pipelines The maximum positive pressures for steel are relatively low and should not be a problem.
Negative pressures for both pipe types are similar. Negative pressures could be of concern if the pipeline is slimed and operated at low storage levels. Even if the pipeline is not slimed and has low friction the Hydraulic Grade Line (HGL) would closely follow the level of the pipeline. This situation should be avoided. The following should be considered if steel is used:
• implement operating rules that prevent full gate operation when the reservoir is at low levels. Even if the pipeline is kept unslimed, although negative pressures are not expected, the HGL is expected to run at the pipeline’s level, which should be avoided;
• regular internal cleaning of the pipeline could be required if sliming becomes an issue;
• ensure that the anti-vacuum valves, near the HTV, are fully operational and are of sufficient capacity.
6.4 Penstock and surge pipe A hydraulic transient analysis of the penstock and surge pipe has been completed. The results of this analysis have been compared to an assessment of the allowable pressures. See Volume 2, Appendix 16 for details of the analysis.
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The strength criteria used to assess the penstock and surge pipe is described in ASCE Steel Penstocks, 1993 (Ref. 11). This is based on the lower of 2/3 of the maximum yield stress or 1/3 of the maximum tensile stress.
The calculated stresses only considered hoop stresses and were calculated assuming pressure rises from Pelton machine operation. Francis machines were not considered.
Increasing the spear closure and opening times can significantly reduce both the positive and negative pressure profile.
However, towards the middle of the penstock the assessment criteria were exceeded. This does not necessarily mean that the penstock is inadequate. Hydro Tasmania has found that for many older penstocks these criteria are exceeded. Given that the criteria are based on 1/3 of the maximum tensile stress, and it is only just exceeded, this penstock should be able to be safely used with the following mitigation measures in place:
• if a new turbine is to be installed then only Pelton machines would be acceptable;
• spear closing times should be greater than 240 seconds;
• ongoing condition monitoring of the penstock should occur.
To prevent overflowing of the surge pipe, due to surges, the pipe needs to be extended by about 13 m (vertical rise of about 3.7 m). Alternatively a 45° bend could be added, along with a small concrete block, to the top of the pipe to divert water during surges.
6.5 Hilltop valve The existing hilltop valve was installed in 1971, and in 1997 it had a new hydraulic power pack and electrical trip added. The valve is designed for isolation of the penstock and also protection of the penstock by automatically closing using stored energy in a counter weight to close on detection of pipeline over velocity. During normal power station operation, the valve would remain open for many months at a time.
The existing hilltop valve is a 48 3/4” bore butterfly valve. The conduit pipe immediately downstream of the valve incorporates a slip joint with loose flange to allow for valve removal. A recent internal inspection has found the valve seal and seat to be in acceptable condition, and some internal corrosion on the valve body.
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The existing valve operation has been problematic with widely varying closure speeds and during test it has failed to begin closing, and failed to fully close. The valve trunions and their greaseless bushes produce excessive friction and the counter weight may not overcome this friction after a period of inactivity, or when closing against flow with maximum lake level.
The hilltop valve area is accessible by vehicle, but it is at the end of a steep 4WD track which would only just allow an all terrain mobile crane access.
Refurbishment of the valve may be possible, but it would require the valve to be removed from the pipeline and taken to a workshop for disassembly. The valve was designed and manufactured by MB John and Hattersley in Ballarat, Victoria, and the existing factory (John Valves) has indicated that these older butterfly valves were designed for quick and easy assembly but are not easy to dismantle, they are difficult to get apart even in a workshop and it frequently results in damage to the blade and shaft. This introduces uncertainty and risk with a refurbishment scope, timing and cost and, for these reasons, it is not the recommended course of action.
It is recommended that procurement and installation of a new valve be considered. The new valve delivery and old valve removal could be combined to use the same single visit of a transport vehicle and all-terrain mobile crane. It is recommended that this new automatic valve be a heavy duty butterfly valve designed for guard duty and closing off pipeline discharge, that it be closed automatically by the stored energy in a counter weight, and opened by a self contained small on-board hydraulic power pack. This new valve could be identical to the proposed new dam outlet valve and so take advantage of some cost savings from the purchase of two identical valves.
It is recommended that the trip actuation of the hilltop valve continue to be available remotely from the power station, or from System Operation if the station is de-manned and remote controlled. Also, that automatic local tripping of the valve continue to be initiated by an over velocity detection device. This may consist of the existing low pressure float switch device, or could consist of a differential pressure measurement across the butterfly valve, for example, on tappings on the inside and outside of one of the pipe bends in the conduit in the hilltop area. Alternatively, the over velocity could be detected via a compact insertion type magnetic or acoustic flow meter of relatively low accuracy.
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Recommendations: • Provide a new automatic counterweight close butterfly guard valve in place of the existing hilltop valve, for penstock protection. It is recommended that this valve be identical to the new guard valve at the dam outlet.
• Provide a new over velocity detection and trip scheme to automatically trip the new hilltop valve.
6.5.1 Air release and anti-vacuum valves
There are two anti-vacuum valves and a single air release valve on the downstream side of the hilltop valve. It is believed that these are all working satisfactorily. The two Glenfield anti- vacuum valves are well over sized for this application. It is recommended that these valves be retained as is.
6.5.2 Power supplies, controls and communications
There is a 6.6 kV feeder into the hilltop valve area, a step-down transformer located in the winch house is used to provide a 415V AC supply, which is reticulated around the area. While some minor remedial work is required, the supply could be left as is.
Currently the HTV has sufficient controls, tripping function, and monitoring from the station. No electrical upgrading is recommended.
6.6 Access to hilltop
6.6.1 Haulageway
The haulageway was installed during 1970 with the new penstock, and it was refurbished in 1997/98 and registered with Workplace Standards Tasmania. The haulage has a rating of 1.5 tonnes, although the winch itself has a nameplate rating of 4.5 tonnes. The haulage can only be operated by a driver from the winch house at the top. It has a high heritage significance and it is recommended that it be retained in working condition.
It currently required re-certification to enable it to operate, and it is recommended that this be done prior to the start of any construction works at the headworks and dam. This requires NDT testing of the wire rope (x-ray), removal of a short length of rope for destructive testing of ultimate tensile strength, and an inspection by a registered plant inspector then re- certification of the haulage.
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It is feasible that the existing haulageway can have its rating increased from 1.5 to 2.0 tonnes, or even 2.5 tonnes, to cope with transporting new hilltop pipe sections. There is sufficient reserve in the haulage to allow its rating to be increased and still maintain a safety factor of 10 or better. The required work would involve modifications to the trolley for handling sections of pipe, updating of existing operating procedures, approval from a registered plant inspector and from Workplace Standards Tasmania to increase the load rating, and re-commissioning of the variable speed drive at the higher load. Alternatively, if the new hilltop pipe can be transported by 4WD vehicle on the existing access road, then the haulageway may not be required at all.
Recommendation: • If the haulageway is required, that it be re-certified and re-registered for use. If transport of new hilltop pipe requires it, then its load rating can be increased up to nominally 2.5 tonnes.
6.6.2 4WD access road
A gravel access road currently leads from the base of the penstock to the hilltop valve area. The road is only suitable for 4WDs (up to small 4WD trucks) as it contains many tight bends and a very steep final section. It is proposed to complete earthworks to improve the tight bends and steep top section to enable frequent use of the road to occur during redevelopment construction works.
6.7 Preservation of sections of existing woodstave pipeline Three sections of the existing woodstave pipeline have been identified for preservation for historical interest. The location of these sections are indicated in Volume 2, Appendix 17. To ensure that the preserved sections remain intact, it will be necessary to internally reinforce the woodstave pipeline and to upgrade the bracing of the supports.
Once dewatering occurs the woodstaves will shrink due to drying and eventually collapse if no measures are taken. The preservation concept proposes to install steel bands on the inside of the pipe to support the timber staves. An air bladder system is also being investigated as an alternative.
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The pipeline supports, particularly the taller piers, are inadequately braced. Once the adjacent pipeline is removed, the preserved sections could become unstable. It is necessary to brace the supports of the preserved sections while the pipeline is intact. The work is relatively simple and consists of longitudinal diagonal bracing in the centre span and a tie along the top of the supports. Ongoing conservation measures would be necessary.
Detailed design would be subject to a Heritage Impact Assessment and would need approval from the Tasmanian Heritage Council.
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7. TRANSMISSION ARRANGEMENT
The current station comprises seven 6.6 kV generators that are connected by power cable to two indoor 6.6 kV switchboards that are interconnected by 6.6 kV cables to form a ring bus with two sectionalising circuit breakers. The cables from each generator connect to a 300 A oil-filled circuit breaker on the switchboard and four 3 MVA, 6.6/11 kV generator transformers (wound as autotransformers) are each cabled to an 800 A oil-filled circuit breaker.
The switch gear, transmission, service transformers and auto transformers have low or medium heritage significance. While an approval from the Tasmanian Heritage Council would be required, there is likely to be some flexibility in future options given the lower heritage significance of these assets.
The output from the generator transformers is connected via two 8.3 km long, double-circuit 11 kV feeders to four circuit breakers on an 11 kV switchboard at the Copper Mines of Tasmania (CMT) substation.
At present, one of the generator transformers is unserviceable due to a fault. Previous investigations on problems encountered with earthing and lightning protection at the power station advocated that these four generator transformers be replaced with double wound transformers. The purpose of this was to prevent lightning surges travelling through the transformer and causing damage to the windings of the generators.
A simple bunding and oil containment system exists for the four generator transformers. Due to the proximity of the Yolande River, this system would need upgrading if larger transformers are installed.
Further discussion of the transmission arrangement can be found in Volume 2, Appendix 18.
The recommended options for the transmission arrangements depend on the decision to refurbish the existing station or install a new machine.
Respectively these arrangements are likely to be:
• Remain connected to Copper Mines of Tasmania providing suitable agreements can be made between the parties involved.
• Retain two of the four transmission circuits, reinsulated to 22kV, and connected to the Queenstown Substation.
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8. LEGISLATIVE APPROVALS
8.1 Introduction The approvals processes, risks and likely issues for the options discussed in this study are largely consistent and therefore can be discussed together.
8.2 Commonwealth
8.2.1 Environment Protection and Biodiversity Conservation Act 1999
The Lake Margaret Power Scheme has been nominated for inclusion on the National Heritage List. The assessment process to determine its merit for inclusion is currently underway, being advertised for public comment until the end of November 2006. While there is currently no legislative impact of the National Heritage List nomination, it is an important consideration in terms of the approval process should the scheme be considered of national significance and entered onto the National Heritage List.
Should the scheme be entered onto the National Heritage List, the Environment Protection and Biodiversity Conservation Act (EPBCA) 1999 becomes applicable for any “Controlled Actions” that may impact upon the value or significance of the place. “Controlled Actions” are assessed by the Commonwealth Department of Environment and Heritage (DEH). This assessment and approval process is significant, in terms of time and effort required to gain approval and introduces an additional layer of process that must be successfully negotiated prior to works commencing
8.3 State
8.3.1 Environmental Management and Pollution Control Act 1994
Neither the minimalist refurbishment or new 10 MW power station option would be classified a Level 2 Activity under the Environmental Management and Pollution Control Act 1994. However, the Board of Environmental Management has the authority to “call in” projects that it deems require environmental assessment. It is considered that this is unlikely due to the small scale of the development options and the minimal environmental impact, given the dam and environmental impact on water flows in the Yolande River are from existing use rights of the current station and are unlikely to be significantly altered.
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8.3.2 Land Use Planning and Approvals Act 1993 and the Historic Cultural Heritage Act 1995
The Lake Margaret Power Scheme has been provisionally listed on the Tasmanian Heritage Register, the provisional listing has the same effect of full listing, therefore no “works” can be undertaken on the site without approval under the Historic Cultural Heritage Act 1995.
Works is quite broad in interpretation and includes “(a) any development; (b) any physical intervention, excavation or action which may result in a change to the nature or appearance of the fabric of a place; (c) any change to the natural or exiting condition or topography of land; and (d) any removal, destruction or lopping of trees otherwise than in accordance with forest practices as defined in the Forest Practices Act 1985; and (e) any removal or vegetation or topsoil.”
Both of the discussed options and some of the works consistent with both options would require approval from the West Coast Council under the West Coast Planning Scheme in accordance with the Land Use Planning and Approvals Act 1993 and from the Tasmanian Heritage Council under the Historic Cultural Heritage Act 1995. This approval process would include an advertising period during which public submissions can be made to the Council.
Due to the interdependencies between the Land Use Planning and Approvals Act 1993 and the Historic Cultural Heritage Act 1995, in regard to undertaking works or development on places listed on the Tasmanian Heritage Register, these acts are dealt with together. In essence, as approval is required under both acts, and they both contain similar components such as notification, public advertising and appeal rights to the same tribunal, it is common place for the assessment under both acts to occur simultaneously. In doing so, any repetition of notification, representations and appeals is removed.
This process would require a high degree of stakeholder consultation and may involve an appeal to the Resource Management and Planning Appeal Tribunal. Such an approval process may take 4 – 6 months from application lodgement to determination.
The Works Application would consider the impact of the proposal on the heritage fabric and value of the site, while the Development Application would relate to more general issues, however those issues specifically listed under the West Coast Planning Scheme include the following:
• avoidance of natural hazards;
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• protection of riparian vegetation;
• road access and setbacks;
• wetlands and waterways;
• bushfire protection.
8.3.3 Threatened Species Protection Act 1995
Should any of the proposed works include vegetation removal, such as the power station building option or a new length of transmission line, this may trigger the Threatened Species Protection Act 1995 should any threatened species be encountered. It is considered that a new transmission line option is more likely to encounter rare species, in comparison to the power station site, which is highly disturbed. The process for gaining a “permit to disturb” involves the submission of a proposal that includes impact management, mitigation and potential offsets, this ensures that no unreasonable negative impact occur.
8.3.4 Aboriginal Relics Act 1975
Any of the proposed works that involve ground disturbance have the possibility of uncovering Aboriginal cultural heritage. These works would include the new power station building and a new transformer yard. The likelihood of finding Aboriginal cultural heritage would first be assessed by a specialist consultant through a desktop study in conjunction with the Tasmanian Aboriginal Land and Sea Council. If considered necessary through the desktop study, ground disturbance monitoring could be required. Ultimately, if an artefact or relic is found during construction a permit would need to be sought.
8.3.5 Forest Practice Act 1985
Should vegetation clearance for a new transmission line option exceed 1 hectare or include vulnerable vegetation communities, a Forest Practices Plan under the Forest Practices Act 1985, would be required to be prepared and approved by a Forest Practices Officer. This process involves no risk and if appropriate information is provided, approval would be granted. Some general environmental management issues would be covered by this assessment process.
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8.3.6 Building Act 2000
Building Approval from the West Coast Council under the Building Act 2000 would be required for works such as:
• doorways,
• windows,
• viewing platforms,
• bunded areas for transformers,
• transformer fire separation walls and
• the new powerhouse.
Prior to Council issuing building approval, both Development and Works approval would need to be granted. The building approval process involves no risk and if appropriate information is provided, approval would be granted.
8.4 Summary It is considered that the most significant issues for approvals could be the Commonwealth assessment under the EPBCA should the Lake Margaret Power Scheme be on the National Heritage List prior to or during the redevelopment works phase, and the West Coast Council and Tasmanian Heritage Council approval processes at the state level.
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9. ENVIRONMENTAL ASSESSMENT OF PROPOSED REDEVELOPMENT OPTIONS
9.1 Introduction Environmental issues that may be impacted upon are common to both redevelopment options. The main environmental issues that would need to be considered as part of the redevelopment of the power station are:
• potential environmental impacts that could result due to the replacement of the woodstave hilltop pipeline;
• potential environmental impacts that may result as part of the construction phase;
• environmental flows in the Yolande River.
9.2 The replacement of the hilltop pipeline This aspect of the redevelopment has potential for environmental impacts to occur from the construction of new pipeline supports and the new pipeline itself. Following selection of the proposed pipeline material (likely to be either a woodstave pipeline or steel) and design of the pipeline and its alignment, potential environmental impacts would be assessed and management measures developed to mitigate any environmental impacts.
9.3 Potential environmental impacts as part of construction There are likely to be potential environmental impacts as part of the reconstruction process. Environmental impacts may result from construction activities such as:
• road or track works required as part of construction;
• transmission line upgrade, if a new alignment or widening of the existing alignment is required.
Following detailed design of the redevelopment of the power station and associated infrastructure, an Environmental Impact Assessment would be required to identify all potential environmental impacts and to develop management mitigation measures to ensure any environmental impact is minimised during construction.
9.4 Environmental flows in the Yolande River It has been assessed that there has been minimal impact on the environmental condition of the Yolande River, downstream of Lake Margaret, as a result of the dam and past operation
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of the power station. These changes are largely mitigated against by inflows that restore natural flow variability and sediments to the system.
It is considered that the provision of a dedicated environmental flow would not significantly improve the environmental condition of the Yolande River downstream given that:
• no threatened species are known to occur within the Yolande River;
• the relative low quality of habitats available to fish and macroinvertebrates;
• the existing increase in baseflow due to inflows from tributaries, groundwater and runoff.
9.5 Other environmental issues Other environmental issues that have been identified in previous studies which are common to both redevelopment options, include:
• maintenance of areas identified as containing asbestos, eg sheeting in the workshop roof;
• a review of the transformer drainage arrangements;
• repair of the transformer bund storage tank, as well as the clean up of previous hydrocarbon spillage around the storage tank;
• assessment of the presence of lead paint in the village houses;
• preparation of a weed management plan for the village area;
• removal of readily accessible rubbish from tip site 4. This tip site is located in a gully beside Leslie Creek;
• drainage works for tip site 5, to divert stormwater runoff and prevent future instability. This site is located next to the access road to the lower power station and has been covered with clay material during road works. Revegetation of this area could also be required to assist with stability and to improve aesthetic values.
9.6 Increased use of the site If the site is to be developed to cater for a greater number of visitors, the following requires consideration:
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• review the capacity of the sewage system;
• review the water supply system;
• upgrading of roads.
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10. ECONOMIC ANALYSIS OF REDEVELOPMENT OPTIONS
10.1 Options comparison Hydro Tasmania has investigated a number of options for redevelopment of the Lake Margaret Power Station. Following evaluation, the two economically favoured options are:
• Minimalist refurbishment of the existing power station
• Build a new power station with a single generator adjacent to the existing power station
Both options are marginally viable within reasonable confidence limits.
Table 10-1 identifies likely up front construction costs for both options and expected range of rate of return on investment. The rate of return is influenced by operation and maintenance costs, energy prices and prices for Renewable Energy Certificates (RECs).
Table 10-1 Economics of favoured options
Upfront IRR Assessed capital cost 80% Option range range confidence % $M IRR 1. Minimalist refurbishment 11-13 6-13 9.5% of existing power station 2. New power station approx 17-20 7-13 11% 10 MW
10.2 Risk assessment A quantitative risk assessment was performed on these parameters to produce a range of possible outcomes as opposed to simply including a contingency assessment.
Detailed cost estimates were analysed by assessing probable, best and worst case outcomes. For instance, larger ranges were placed on estimates which were considered to be at risk of commodity price rises between now and when prices can be confirmed. A Monte Carlo simulation was performed to determine a confidence range for the cost of each option. Similarly ranges were assessed on the revenue side for future energy and RECs pricing.
The final outcome is sensitive to application and pricing of RECs.
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10.3 Impact of Mandated Renewable Energy Target The Australian Government's Mandatory Renewable Energy Target (MRET) commenced on 1 April 2001. The Renewable Energy (Electricity) Act 2000 requires the generation of 9,500 gigawatt hours of extra renewable electricity per year by 2010.
The intention of MRET was to introduce a renewable energy target as part of a package of measures designed to support the renewable energy industry. The renewable energy target scheme imposed a legal obligation on electricity retailers and other large electricity customers to source an additional 2% of their electricity from renewable or specified waste- product energy sources by 2010. The objective of the scheme is to reduce emissions of greenhouse gases and encourage the development of a renewable energy industry in Australia.
In order to implement the scheme a market for Renewable Energy Certificates (RECs) has been established. A generator may qualify for RECs for either a new renewable power station or a demonstrated increase in production from an existing power station above an agreed baseline.
Each MWhr that is produced under the RECs scheme is given a certificate. These certificates are traded in the RECs market. The Commonwealth legislation defines liable parties (retailers and large wholesale consumers) who need to purchase a certain number of RECs, depending on the scale of their electricity purchases.
Under current RECs rules, if the Lake Margaret Power Station is shutdown for three years, and at least 50% of the cost of the same station built on a greenfield site is invested into a redevelopment, then it would become eligible for RECs for all of its production. This is known as a zero RECs baseline.
For this reason, only the option of a new power station qualifies for full RECs. A refurbishment project would not cost as much as 50% of a scheme replacement cost. The replacement cost of the whole scheme is assessed to be in the order of $32 million.
Economic analysis has assumed that:
• the current RECs baseline would remain unchanged for the refurbishment of the existing power station;
• a new power station option would gain the benefit of a zero RECs baseline.
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The future of MRET or replacement schemes is uncertain. For the purpose of this study it is assumed that eligibility for future schemes would be on a similar basis.
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11. CONCLUSIONS AND RECOMMENDATIONS
The analyses undertaken as part of this feasibility study indicate that it is marginally economically viable to proceed with redevelopment of the Lake Margaret Power Scheme. Both the options of minimalist refurbishment of the existing power station and the building of a new power station are marginally economically viable.
The refurbishment option has the following advantages:
• lower capital cost;
• lower equity requirements;
• less time, expense and uncertainty on heritage and development approval matters;
• earlier completion;
• lower up-front capital cost;
The new power station has the following advantages:
• higher NPV;
• more renewable energy generated;
• more certainty on future O&M costs;
• easier to manage the safety risk with new equipment.
Next steps:
• Seek feedback from the Lake Margaret Community Liaison Group regarding the analysis and findings in this Feasibility Study.
• Incorporate feedback from the community response.
• Progress Works Application and appeal to Resource Management and Planning Appeal Tribunal (RMPAT) for removal of the existing woodstave hilltop pipeline.
• Hydro Tasmania will call for expressions of interest for tourism development at the site.
• Board decision on business case and future options for the redevelopment
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12. GLOSSARY
AC Alternating Current.
AEP Annual Exceedance Probability (AEP) is the probability of equalling or exceeding a value in any given year. For example a 1:100 AEP flood has a 1 in 100 chance of being equalled or exceeded in any given year.
ANCOLD The Australian National Committee on Large Dams Incorporated (ANCOLD Inc) is an incorporated voluntary association of organisations and individual professionals with an interest in dams in Australia.
ASCE American Society of Civil Engineers.
BCA Building Code of Australia.
CB Circuit Breaker.
CMP The Conservation Management Plan (CMP) is primarily concerned with the heritage values of Lake Margaret and how best to retain these values for the range of options available for the future. The plan sets out a history of the site, establishes a basis for significance and sets out policies to guide shutdown and closure.
CMT Copper Mines of Tasmania (CMT) which owns the Mt Lyell Copper Mine.
DC Direct Current.
DDF Dielectric Dissipation Factor (tan delta).
DEH Commonwealth Department of the Environment and Heritage.
DFL The Design Flood Level (DFL) is the flood level for which the dam has been designed.
EL-CID Electromagnetic-Core Imperfection Detector.
EPBCA Environment Protection and Biodiversity Conservation Act.
FEA Finite Element Analysis (FEA) is a computer simulation technique used in engineering analysis. A common use of FEA is in the determination of stresses and displacements.
FSL Full Supply Level (FSL) of a storage.
GRP Glass Reinforced Plastic (GRP) is a composite material made of plastic reinforced with fine fibres of glass. It is commonly referred to as fibreglass.
HCHA Historic Cultural Heritage Act.
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HGL The Hydraulic Grade Line (HGL) is a line whose plotted ordinate position represents the sum of pressure head plus elevation head for the various positions along a given fluid flow path, such as along a pipeline.
HPU Hydraulic Power Unit.
HT Hydro Tasmania.
HTV The Hilltop Valve (HTV) prevents flow between the hilltop pipeline and the penstock.
HV High Voltage.
IR Insulation Resistance.
IRR Internal Rate of Return.
JMG Johnstone McGee and Gandy.
MIV The Main Inlet Valve (MIV) prevents flow from the penstock to the machine.
MRET The Australian Government's Mandatory Renewable Energy Target (MRET) commenced on 1 April 2001. The intention of MRET was to introduce a renewable energy target as part of a package of measures designed to support the renewable energy industry.
NB Nominal Bore (NB) is the internal diameter of a pipe or fitting.
NDT Non-destructive Testing.
NPV Net Present Value.
PCB Polychlorinated Biphenyl.
PD Partial Discharge.
PLC Programmable Logic Controller.
RECs Renewable Energy Credits (RECs) are a Commonwealth Government incentive to develop new renewable energy. Each MWhr that is produced under the RECs scheme is given a certificate. These certificates are traded in the RECs market. The Commonwealth legislation defines liable parties (retailers and large wholesale consumers) who need to purchase a certain number of RECs, depending on the scale of their electricity purchases.
RTD Resistance Temperature Detector.
SCADA SCADA is the acronym for Supervisory Control and Data Acquisition. SCADA systems are used to monitor or control systems.
SKM Sinclair Knight Merz.
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SMEC Snowy Mountains Engineering Corporation.
SWL Safe Working Load.
THR Tasmanian Heritage Register.
UB Universal Beam.
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13. REFERENCES
1. HEC (May 1994) Lake Margaret Redevelopment Study Phase 1.
2. HT (February 2002) Lake Margaret Redevelopment Study 2.
3. HT (April 2003) Lake Margaret Power Station Upgrade Study, 107864-Report-001.
4. Godden Mackay (May 1994) Lake Margaret Cultural Heritage Study.
5. Paul Davies Pty Ltd (March 2006) Lake Margaret Power Scheme – A Conservation Management Plan.
6. Sinclair Knight Merz (October 2006) Hydro Tasmania, Lake Margaret Woodstave Pipeline Review.
7. Canbar Inc (October 2006) Wood Stave Penstock Inspection, Lake Margaret Power Scheme.
8. HT (May 2002) Margaret Dam Comprehensive Safety Assessment 1996-2001.
9. Inspiring Place (June 2006) Indicative Assessment of Tourism Potential for Lake Margaret.
10. Johnstone, McGee & Gandy (September 2006) Initial Pre-feasibility Report for Redevelopment of Lake Margaret Power Scheme.
11. American Society of Civil Engineers (1993) ASCE Steel Penstocks.
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